Canadian Natural Resources Limited Announces 2014 First Quarter Results

Canadian Natural Resources Limited Announces 2014 First Quarter Results 
CALGARY, ALBERTA -- (Marketwired) -- 05/08/14 --   Canadian Natural
Resources Limited (TSX: CNQ) (NYSE: CNQ) 
Commenting on first quarter results, Steve Laut, President of
Canadian Natural stated, "Canadian Natural had a solid start to the
year, with consistent organic growth in North America production as
expected. North America E&P crude oil and NGLs production grew by 5%
over the previous quarter. Subsequent to the quarter the acquisition
of certain assets closed, the integration of people is now complete
and the integration of those assets is progressing. We have expanded
our strong portfolio, which we will continue to develop in a prudent
and disciplined manner, enabling us to maximize value for our
shareholders. As a result of the recent acquisitions and our ongoing
development opportunities, our 2014 development capital budget has
been increased by $425 million and our 2014 annual production
guidance has increased, with the midpoint of crude oil and NGLs
production increasing by 3% or 15,000 barrels per day, and the
midpoint of natural gas production increasing by 30% or 360 million
cubic feet per day. 
Canadian Natural continues to execute on its defined growth plan and
achieved record quarterly production in primary heavy crude oil,
Pelican Lake heavy crude oil and North America light crude oil and
NGLs. Additionally, we had continued strong production at Horizon,
with quarterly production averaging 113,000 barrels per day, and
April 2014 production of approximately 119,000 barrels per day. Our
Kirby South SAGD project is progressing well and we are targeting a
strong ramp up in production to the 40,000 barrel per day facility
capacity by the end of 2014.  
We will continue to focus on execution and capital discipline to
deliver on our defined growth plan. This prudent development of our
diverse asset base enables us to generate increasing free cash flow
to allocate to resource development, sustainable dividends, share
purchases, opportunistic acquisitions, and debt repayment."  
Canadian Natural's Chief Financial Officer, Corey Bieber, continued,
"The solid production growth this quarter combined with strong crude
oil and natural gas pricing, led to an increase in cash flow by 20%
over the fourth quarter of 2013.  
We have demonstrated the value of our large and diverse asset base as
we remain on track to deliver a solid year of cash flow generation.
This increase in cash flow enables us to maximize returns to our
shareholders in the form of sustainable dividends and share
purchases. During the first quarter of 2014 we increased our
quarterly dividend to $0.225 per common share from $0.20 per common
share. This is our fourteenth consecutive year of quarterly dividend
increases and represents a year over year increase of 80% in the
quarterly dividend. Subsequent to the quarter, we renewed our Normal
Course Issuer Bid. In 2014, year to date, we have purchased 2,105,000
common shares at an average price of $37.86 per common share.  
Our disciplined strategy and financial strength will enable us to
continue to execute on the significant growth opportunities which we
have in the near, mid and long-term." 
QUARTERLY HIGHLIGHTS 


 
 
                                                    Three Months Ended      
                                           ---------------------------------
($ Millions, except per common share            Mar 31     Dec 31     Mar 31
 amounts)                                         2014       2013       2013
----------------------------------------------------------------------------
Net earnings                                $      622 $      413 $      213
  Per common share - basic                  $     0.57 $     0.38 $     0.19
    - diluted                               $     0.57 $     0.38 $     0.19
Adjusted net earnings from operations (1)   $      921 $      563 $      401
  Per common share - basic                  $     0.85 $     0.52 $     0.37
    - diluted                               $     0.85 $     0.52 $     0.37
Cash flow from operations (2)               $    2,146 $    1,782 $    1,571
  Per common share - basic                  $     1.97 $     1.64 $     1.44
    - diluted                               $     1.97 $     1.64 $     1.44
Capital expenditures, net of dispositions   $    1,893 $    2,091 $    1,736
 
Daily production, before royalties                                          
  Natural gas (MMcf/d)                           1,175      1,195      1,150
  Crude oil and NGLs (bbl/d)                   488,788    478,038    489,157
  Equivalent production (BOE/d) (3)            684,647    677,242    680,844
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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 $2.15 billion in Q1/14 compared to approximately $1.57
billion in Q1/13 and $1.78 billion in Q4/13. The increase in cash
flow from Q4/13 reflects higher North America crude oil and NGLs and
natural gas netbacks, higher North America crude oil sales volumes
and the impact of the weaker Canadian dollar, offset by lower crude
oil sales volumes in the Offshore Africa segment. Due to the nature
of Floating Production, Storage and Offloading ("FPSO") vessel
operations, no crude oil liftings or sales occurred in Offshore
Africa operations during Q1/14. The resulting cash flow from Q1/14
production, to be realized in Q2/14 once liftings occur, is targeted
to be approximately $50 million. 
- Adjusted net earnings from operations for Q1/14 were $921 million,
compared to adjusted net earnings of $401 million in Q1/13 and $563
million Q4/13. Changes in adjusted net earnings reflect the changes
in cash flow from operations as well as lower depletion, depreciation
and amortization expense from both Q1/13 and Q4/13.  
- Total crude oil and NGLs production for Q1/14 averaged 488,788
barrels per day ("bbl/d"). The strong production performance was
largely driven by:  
-- record production levels in primary heavy crude oil,  
-- record Pelican Lake heavy crude oil production,  
-- record North America NGLs and light crude oil production,  
-- continued safe, steady and reliable production at Horizon Oil
Sands ("Horizon") operations. 
- In Q1/14, primary heavy crude oil operations achieved record
quarterly production of approximately 142,000 bbl/d. Primary heavy
crude oil production increased 7% and 6% from Q1/13 and Q4/13 levels,
respectively, due to strong results from the Company's effective and
efficient drilling program.  
- In Q1/14, Pelican Lake operations achieved record quarterly heavy
crude oil production volumes of approximately 48,000 bbl/d, a 26%
increase from Q1/13 volumes and a 4% increase from Q4/13 volumes.
This is the fifth consecutive quarter of production increases, which
reflects Canadian Natural's continued success in developing,
implementing and optimizing polymer flooding technology.  
- Kirby South, a 100% owned and operated SAGD project, was completed
during Q3/13 ahead of schedule and on budget. The reservoir is
responding as expected with Q1/14 production averaging 5,000 bbl/d
and April 2014 production averaging approximately 14,000 bbl/d. Kirby
South production is targeted to grow to facility capacity of 40,000
bbl/d by year end.  
- The Kirby North Phase 1 ("Kirby North") project is continuing
toward commencement of construction and regulatory approvals are
progressing. Targeted project capital for Kirby North is $1.45
billion, equating to approximately $36,000 per flowing barrel at a
project capacity of 40,000 bbl/d. Detailed engineering on the Central
Processing Facility is essentially complete and first steam-in is
targeted for Q4/16, subject to regulatory approvals. 
- During Q1/14 Horizon continued to achieve strong and reliable
operating performance, with SCO production averaging approximately
113,000 bbl/d, a 4% increase from Q1/13 levels and a 1% increase over
Q4/13 levels. April 2014 SCO production averaged approximately
119,000 bbl/d. Horizon production is targeted to increase in 2014 by
11%, an average increase of 11,000 bbl/d from 2013 levels, as a
result of the continued focus on effective and efficient operations.  
- Q1/14 total natural gas production was 1,175 MMcf/d, an increase of
2% from Q1/13 levels and a decrease of 2% from Q4/13 levels. The
increase in natural gas production from Q1/13 levels is due to the
successful completion of the Septimus plant expansion, a concentrated
liquids-rich natural gas drilling program, as well as minor property
acquisitions. The minor decrease in natural gas production from Q4/13
was primarily a result of normal production declines.  
- During Q1/14, the Company agreed to acquire certain assets in areas
adjacent or proximal to Canadian Natural's current Canadian
operations. These assets are high quality, concentrated liquids-rich
natural gas weighted assets, with additional light crude oil
exposure. The transactions closed in Q2/14 and include associated key
strategic facilities, a royalty revenue stream and undeveloped land.
The integration of people is now complete and Canadian Natural is
working to maximize efficiencies of the integrated operations while
high grading opportunities in the Company's large and diverse
portfolio.  
- As expected, heavy crude oil differentials narrowed during Q1/14,
resulting in favorable price realizations for the Company. The WCS
heavy oil differential ("WCS differential") as a percent of WTI
averaged 24% in Q1/14 compared to 34% in Q1/13 and 33% in Q4/13.  
- Under the Company's Normal Course Issuer Bid, Canadian Natural has
purchased 2,105,000 common shares year to date for cancellation at an
average price of $37.86 per common share, which includes 330,000
common shares purchased subsequent to March 31, 2014 at a weighted
average price of $43.44 per common share. 
- Canadian Natural declared a quarterly cash dividend on common
shares of C$0.225 per share payable on July 1, 2014. 
OPERATIONS REVIEW AND CAPITAL ALLOCATION  
In order to facilitate efficient operations, Canadian Natural focuses
its activities in core regions where the Company owns 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 production facilities by processing its
own or third party volumes, thereby increasing control over
production costs. Furthermore, 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)                                         
                                           Three Months Ended Mar 31        
                                    ----------------------------------------
                                            2014                2013        
                                         Gross      Net      Gross      Net 
----------------------------------------------------------------------------
Crude oil                                  300      271        312      300 
Natural gas                                 32       25         18       15 
Dry                                          4        3          6        5 
----------------------------------------------------------------------------
Subtotal                                   336      299        336      320 
Stratigraphic test / service wells         330      330        305      305 
----------------------------------------------------------------------------
Total                                      666      629        641      625 
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  Success rate (excluding                                                   
   stratigraphic test / service                                             
   wells)                                            99%                 98%
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----------------------------------------------------------------------------
 
North America Exploration and Production                                    
 
Crude oil and NGLs - excluding Thermal In Situ Oil Sands                    
                                                  Three Months Ended        
                                           ---------------------------------
                                               Mar 31     Dec 31     Mar 31 
                                                 2014       2013       2013 
----------------------------------------------------------------------------
Crude oil and NGLs production (bbl/d)         266,110    254,162    236,600 
----------------------------------------------------------------------------
 
Net wells targeting crude oil                     263        299        271 
Net successful wells drilled                      260        289        267 
----------------------------------------------------------------------------
  Success rate                                     99%        97%        99%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

-North America crude oil and NGLs production averaged 266,110 bbl/d in
Q1/14, an increase of 12% from Q1/13 levels and 5% from Q4/13 levels. 
- In Q1/14, primary heavy crude oil operations achieved record
quarterly production of approximately 142,000 bbl/d. Primary heavy
crude oil production increased 7% and 6% from Q1/13 and Q4/13 levels,
respectively, due to strong results from the Company's effective and
efficient drilling program. Canadian Natural continued with its large
and cost efficient drilling program with 224 net primary heavy crude
oil wells completed in Q1/14. Canadian Natural's primary heavy crude
oil assets provide strong netbacks and a high return on capital in
the Company's portfolio of diverse and balanced assets. 
- In Q1/14, Pelican Lake operations achieved record heavy crude oil
quarterly production volumes of approximately 48,000 bbl/d, a 26%
increase from Q1/13 volumes and a 4% increase from Q4/13 volumes.
This is the fifth consecutive quarter of production increases, which
reflects Canadian Natural's continued success in developing,
implementing and optimizing polymer flooding technology. Pelican
Lake's industry leading operating costs of $9.65/bbl in Q1/14
represent a 28% decrease in operating costs from Q1/13. The
increasing polymer flood production response combined with continued
optimization and effective and efficient operations have driven cost
improvements.  
- North America light crude oil and NGLs achieved record quarterly
production of approximately 75,900 bbl/d in Q1/14. Production
increased 16% from Q1/13 levels and 3% from Q4/13 levels, as a result
of a successful Q1/14 drilling program and increased NGLs production
associated with the Septimus project expansion. The Company drilled
39 net light crude oil wells in Q1/14. 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.  


 
 
Thermal In Situ Oil Sands                                                   
                                                  Three Months Ended        
                                           ---------------------------------
                                               Mar 31     Dec 31     Mar 31 
                                                 2014       2013       2013 
----------------------------------------------------------------------------
Bitumen production (bbl/d)                     82,077     78,069    108,889 
----------------------------------------------------------------------------
 
Net wells targeting bitumen                        11         38         33 
Net successful wells drilled                       11         35         33 
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  Success rate                                    100%        92%       100%
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-Q1/14 thermal in situ production volumes were 82,077 bbl/d, at the
high end of the Company's previously issued guidance of 75,000 to
83,000 bbl/d.  
- Kirby South, a 100% owned and operated SAGD project, was completed
during Q3/13 ahead of schedule and on budget. The reservoir is
responding as expected with Q1/14 production averaging 5,000 bbl/d
and April 2014 production averaging approximately 14,000 bbl/d. At
the end of Q1/14, 25 well pairs had been converted to full SAGD
production with a further 4 well pairs converted to production
subsequent to Q1/14. The remaining 20 well pairs are progressing
through the steam circulation phase to initiate the SAGD process. The
wells at Kirby South are performing as expected and production is
targeted to grow to facility capacity of 40,000 bbl/d by year end.  
- The Kirby North project is continuing toward commencement of
construction and regulatory approvals are progressing. Targeted
project capital for Kirby North is $1.45 billion, equating to
approximately $36,000 per flowing barrel at a project capacity of
40,000 bbl/d. The Kirby North project includes 56 well pairs and
expansion infrastructure for future growth. Detailed engineering on
the Central Processing Facility is essentially complete and first
steam-in is targeted for Q4/16, subject to regulatory approvals. 
- During Q2/13, bitumen emulsion was discovered at surface at 4
separate locations in the Company's Primrose development area, 3 at
Primrose East and 1 at Primrose South. The cleanup of all 4 sites is
complete and the causation review of the bitumen emulsion seepage is
nearing completion. Canadian Natural continues to work
collaboratively with the Alberta Energy Regulator ("AER") on the
causation review of the bitumen emulsion seepage. The Company's near
term steaming plan at Primrose has been modified as a result of the
seepages, with steaming being temporarily reduced in certain areas.
Canadian Natural believes that reserves recovered from the Primrose
area over its life cycle will be substantially unchanged and
production guidance for 2014 also remains unchanged.  
- Concurrent with the causation review, Canadian Natural has
developed methods to prevent seepages for all potential failure
mechanisms. This includes the remediation of legacy wellbores,
modified steaming strategies, enhanced monitoring techniques and
proactive response strategies. 


 
 
Natural Gas                                                                 
                                                  Three Months Ended        
                                           ---------------------------------
                                               Mar 31     Dec 31     Mar 31 
                                                 2014       2013       2013 
----------------------------------------------------------------------------
Natural gas production (MMcf/d)                 1,147      1,165      1,125 
----------------------------------------------------------------------------
 
Net wells targeting natural gas                    25         11         16 
Net successful wells drilled                       25         11         15 
----------------------------------------------------------------------------
  Success rate                                    100%       100%        94%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

-North America natural gas production averaged 1,147 MMcf/d for Q1/14,
an increase of 2% from Q1/13 levels and a decrease of 2% from Q4/13
levels. The increase in natural gas production from Q1/13 was due to
the successful completion of the Septimus plant expansion, a
concentrated liquids-rich natural gas drilling program, as well as
minor property acquisitions. The minor decrease in natural gas
production from Q4/13 was primarily a result of normal production
declines.  
- Subsequent to Q1/14, Canadian Natural completed certain light crude
oil and natural gas property acquisitions in areas adjacent or
proximal to the Company's current operations. Canadian Natural has
reviewed the opportunities across its portfolio and, to maximize
value and reduce per unit production expenses, the Company will
increase natural gas capital allocation by $210 million for 2014. The
additional capital will be allocated to recently acquired assets to
consolidate facilities, drill additional wells for land retention,
conduct facility turnarounds and continue with the fabrication of the
Ferrier central processing modules. These activities will enhance
production while reducing the operating costs on the acquired assets. 
International Exploration and Production 


 
 
                                                   Three Months Ended       
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
                                                  2014       2013       2013
----------------------------------------------------------------------------
Crude oil production (bbl/d)                                                
  North Sea                                     16,715     20,155     18,774
  Offshore Africa                               10,791     13,379     16,112
----------------------------------------------------------------------------
Natural gas production (MMcf/d)                                             
  North Sea                                          7          7          1
  Offshore Africa                                   21         23         24
----------------------------------------------------------------------------
Net wells targeting crude oil                        -          -          -
Net successful wells drilled                         -          -          -
----------------------------------------------------------------------------
  Success rate                                       -          -          -
----------------------------------------------------------------------------
----------------------------------------------------------------------------

-International crude oil production averaged 27,506 bbl/d during
Q1/14, an 18% decrease from Q4/13 levels, and in line with stated
guidance of 26,000 to 29,000 bbl/d. This decrease was primarily as a
result of a temporary shut-in at the Baobab field during the quarter,
unplanned downtime at the Tiffany field, as well as the planned
permanent cessation of production at Murchison in Q1/14. 
- Due to the nature of FPSO vessel operations, no crude oil liftings
or sales occurred in Offshore Africa operations during Q1/14. The
resulting cash flow from Q1/14 production, to be realized in Q2/14
once liftings occur, is targeted to be approximately $50 million. 
- Production at the Baobab field was temporarily shut-in during Q4/13
as a result of a mooring line failure on the FPSO vessel in December
2013. The Company successfully completed the permanent repairs on the
mooring lines in March 2014.  
- During Q4/13 the Company contracted a drilling rig for a 6 well
(3.5 net) drilling program at the Baobab field in Cote d'Ivoire. This
rig is expected to arrive no later than Q1/15 to commence an
approximate 16-month light crude oil drilling program, which is
targeted to add 11,000 BOE/d of net production when complete.  
- Subsequent to Q1/14, Canadian Natural contracted a drilling rig to
undertake the 12-month light crude oil infill drilling program at
Espoir, Cote d'Ivoire. The development of Espoir is now targeted to
commence in the second half of 2014 with a 10 well (5.9 net) drilling
program. This program is targeted to add 5,900 BOE/d of net
production when complete.   
- Canadian Natural previously acquired two blocks in Cote d'Ivoire
which are prospective for deepwater channel/fan structures similar to
Jubilee crude oil discoveries in Offshore Africa. Subsequent to
Q1/14, an exploratory well was drilled on Block CI-514, in which the
Company has a 36% working interest. The well encountered a series of
sands approximately 350 metres thick which contain a hydrocarbon
column of approximately 40 metres of light oil with 34 degree API
gravity. The well, which demonstrated the presence of a working
petroleum system, was plugged and the data gathered will be evaluated
to determine the extent of the accumulation and the future appraisal
plan. These results enhance the prospectivity of Canadian Natural's
Block CI-12, located approximately 35 km west of Canadian Natural's
current production at Espoir and Baobab.  
- In Block 11B/12B, in South Africa, the operator is targeting to
commence drilling the first exploration well in Q3/14. Canadian
Natural has a 50% interest in an exploration right located in the
Outeniqua Basin, approximately 175 kilometers off the southern coast
of South Africa. 
- Banff/Kyle, with combined net production of approximately 3,500
bbl/d, was suspended in Q1/11 after suffering storm damage. The FPSO
has been repaired, is back in the field and is currently being tied
in to the subsea system, with production targeted to resume early in
Q3/14.  
- International capital guidance increased by $100 million for 2014,
largely as a result of foreign exchange rate fluctuations, and, to a
lesser extent, an increase in the targeted cost to drill in Offshore
South Africa, in excess of Canadian Natural's carried costs.  
North America Oil Sands Mining and Upgrading - Horizon 


 
 
                                                   Three Months Ended       
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
                                                  2014       2013       2013
----------------------------------------------------------------------------
Synthetic crude oil production (bbl/d)         113,095    112,273    108,782
----------------------------------------------------------------------------
----------------------------------------------------------------------------

-During Q1/14 Horizon continued to achieve strong and reliable
operating performance, with SCO production averaging approximately
113,000 bbl/d, a 4% increase from Q1/13 levels and a 1% increase over
Q4/13 levels. April 2014 SCO production was approximately 119,000
bbl/d. Horizon production is targeted to increase in 2014 by 11%, an
average increase of 11,000 bbl/d from 2013 levels, as a result of the
continued focus on effective and efficient operations.  
- In Q1/14 Horizon generated strong operating cash flow due to high
SCO sales volumes supported by higher realized SCO pricing. Horizon
operating costs are targeted to decline with the phased expansion of
production capacity.  
- Canadian Natural continues to deliver on its strategy to transition
to a longer life, low decline asset base while providing significant
and growing free cash flow. Canadian Natural's staged expansion to
250,000 bbl/d of SCO production capacity continues to progress on
track and within sanctioned cost estimates.  
- The staged Phase 2/3 expansion at Horizon continues to progress in
Q1/14:  
-- Overall Horizon Phase 2/3 expansion is 37% physically complete.  
-- Reliability - Tranche 2 is 97% physically complete. This phase
will increase performance, overall production reliability and the Gas
Recovery Unit will recover additional SCO barrels in 2014.  
-- Directive 74 includes technological investment and research into
tailings management. This project remains on track and is physically
26% complete.  
-- Phase 2A is a coker expansion which will utilize pre-invested
infrastructure and equipment to expand the Coker Plant and alleviate
the current bottleneck. The expansion is 84% physically complete with
current progress tracking ahead of schedule. The coker tie-in was
originally scheduled to be completed in mid-2015; however, due to
strong construction performance and the early completion of the coker
installation, the Company has accelerated the tie-in to September
2014. An increase in Horizon SCO production capacity of approximately
12,000 bbl/d is targeted to occur subsequent to the completion of the
coker tie-in.  
-- Phase 2B is 28% physically complete. This phase expands the
capacity of major components such as gas/oil hydrotreatment, froth
treatment and the hydrogen plant. This phase is targeted to add
another 45,000 bbl/d of production capacity in 2016.  
-- Phase 3 is on track and on schedule. This phase is 26% physically
complete, and includes the addition of supplementary extraction
trains. This phase is targeted to increase production capacity by
80,000 bbl/d in 2017 and will result in additional reliability,
redundancy and significant operating cost savings.  
-- The projects currently under construction continue to progress on
track and within sanctioned cost estimates.  
- On the Phase 2/3 expansion Canadian Natural has committed to
approximately 63% of the Engineering, Procurement and Construction
contracts. Over 57% of the construction contracts have been awarded
to date, with 85% being lump sum, ensuring greater cost certainty.   
MARKETING 


                                                   Three Months Ended       
                                           ---------------------------------
                                               Mar 31     Dec 31     Mar 31 
                                                 2014       2013       2013 
----------------------------------------------------------------------------
Crude oil and NGLs pricing                                                  
  WTI benchmark price (US$/bbl) (1)         $   98.61  $   97.50  $   94.34 
  WCS blend differential from WTI (%) (2)          24%        33%        34%
  SCO price (US$/bbl)                       $   96.45  $   88.37  $   95.24 
  Condensate benchmark pricing (US$/bbl)    $  102.53  $   94.30  $  107.18 
  Average realized pricing before risk                                      
   management (C$/bbl) (3)                  $   79.68  $   69.38  $   60.87 
Natural gas pricing                                                         
  AECO benchmark price (C$/GJ)              $    4.52  $    2.99  $    2.92 
  Average realized pricing before risk                                      
   management (C$/Mcf)                      $    5.69  $    3.62  $    3.51 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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)
----------------------------------------------------------------------------
2014                                                                        
 January        $94.86           31%       $(7.12)      $13.40        $3.35 
 February      $100.68           19%        $1.97        $8.19        $5.15 
 March         $100.51           21%       $(0.95)       $7.04        $3.37 
 April         $102.03           22%       $(2.56)       $5.59        $1.91 
 May(i)         $99.50           19%        $4.09        $8.78        $3.36 
 June(i)        $98.79           17%        $3.00        $9.18        $2.04 
----------------------------------------------------------------------------
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(i)Based on current indicative pricing as at May 2, 2014. 
- The Company average realized pricing increased in Q1/14 over Q1/13
and Q4/13 pricing due to strong benchmark pricing, narrow WCS
differentials and the weakening of the Canadian dollar relative to
the US dollar.  
- Overall Q1/14 was a strong quarter for commodity pricing:  
-- the WCS differential narrowed to 24% in Q1/14 from 33% in Q4/13,  
-- the SCO price increased by 9% in Q1/14 over Q4/13 pricing to
$96.45, and  
-- AECO natural gas prices for Q1/14 increased 51% to $4.52 over
Q4/13 prices.  
- The WCS differential averaged 24% during Q1/14 compared with 34% in
Q1/13 and 33% in Q4/13. During Q1/14 the WCS differential due to the
reinstatement of third party refinery operations after planned and
unplanned maintenance, increased demand as a result of third party
refinery expansion and higher refinery utilization. The Company
anticipates less volatility in the WCS differential in the latter
half of 2014 as additional heavy crude oil conversion and pipeline
capacity come on stream.  
- Subsequent to Q1/14, the WCS differential averaged 22% in April
2014, and the indicative WCS differential for May 2014 is
approximately 19% and June 2014 is approximately 17%. The WCS
differential is directionally tightening due to increased demand for
heavier crudes, as a result of third party refinery expansion and
higher refinery utilization.  
- Canadian Natural contributed 172,000 bbl/d of its heavy crude oil
stream to the WCS blend in Q1/14. The Company remains the largest
contributor to the WCS blend, accounting for over 55% of the total
blend this quarter.  
- SCO pricing during Q1/14 was comparable to Q1/13 and increased 9%
from Q4/13, reflecting increased demand, benchmark pricing,
prevailing differentials and the alleviation of logistical
constraints between Cushing, Oklahoma and the U.S. Gulf Coast.  
- During Q1/14, AECO natural gas prices increased 55% over Q1/13
levels and 51% from Q4/13 levels. Natural gas prices increased due to
increased winter weather related natural gas demand. The colder than
normal winter resulted in natural gas storage inventories falling
below five-year lows in the US and Canada.  
NORTH WEST REDWATER UPGRADING AND REFINING  
The North West Redwater refinery, upon completion, will strengthen
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 pricing volatility in all Western
Canadian heavy crude oil. The Company has a 50% interest in the North
West Redwater Partnership. Work is progressing and site preparation
and deep underground construction is underway. 
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, US commercial
paper program, diverse asset base and related capital expenditure
programs and commodity hedging policy all support a flexible
financial position and provide the appropriate 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
684,647 BOE/d for Q1/14 with approximately 98% of production located
in G8 countries.  
- During Q1/14 Canadian Natural entered into an agreement to acquire
certain Canadian crude oil and natural gas properties. The acquired
asset package includes a royalty revenue stream which is targeted to
earn approximately $75 million in pre-tax cash flow during 2014.
Canadian Natural is reviewing the options to combine the acquired
royalty revenue stream with its own royalty revenue portfolio for
either the creation of a new vehicle to provide steady cash flow to
current shareholders or monetization through a sale package later in
2014. The targeted pre-tax cash flow from the combined royalty
revenue streams is expected to be between $140 million and $150
million in 2014.  
- Canadian Natural has a strong balance sheet with debt to book
capitalization of 28% and debt to EBITDA of 1.1x at March 31, 2014.
On April 1, 2014, following the acquisition of certain properties for
cash consideration of approximately $3.1 billion, the Company's debt
to book capitalization was 34%.   
- Canadian Natural maintains significant financial stability and
liquidity represented by bank credit facilities. As at March 31,
2014, the Company had in place bank credit facilities of $5,803
million, of which $4,561 million, net of commercial paper issuances
of $553 million, was available. Credit facilities at March 31, 2014
included a $1,000 million non-revolving term credit facility arranged
in connection with the acquisition of certain producing Canadian
crude oil and natural gas properties announced in Q1/14.   
- During Q1/14, the Company issued US$500 million of three-month
London Interbank Offered Rate ("LIBOR") plus 0.375% notes due March
2016, and concurrently, entered into cross currency swaps to fix the
foreign currency exchange rate risk at three-month Canadian Dealer
Offered Rate ("CDOR") plus 0.309% and $555 million. In addition, the
Company issued US$500 million of 3.80% notes due April 2024. Proceeds
from the securities were used to repay bank indebtedness. At March
31, 2014, the Company had maturities of long-term debt aggregating
$945 million over the next 12 months (US$500 million due November
2014 and US$350 million due December 2014).  
- 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. Details of
the Company's commodity hedging program can be found on the Company's
website at www.cnrl.com.  
- Subsequent to Q1/14, Toronto Stock Exchange accepted notice of
Canadian Natural's Normal Course Issuer Bid through facilities of
Toronto Stock Exchange and the New York Stock Exchange. The notice
provides that Canadian Natural may, during the 12 month period
commencing April 2014 and ending April 2015, purchase for
cancellation on Toronto Stock Exchange and the New York Stock
Exchange up to 54,596,899 common shares.  
- Under the Company's Normal Course Issuer Bid, Canadian Natural has
purchased 2,105,000 common shares year to date for cancellation at an
average price of $37.86 per common share, which includes 330,000
common shares purchased subsequent to March 31, 2014 at a weighted
average price of $43.44 per common share.  
- Canadian Natural's Board of Directors has declared a quarterly cash
dividend on common shares of C$0.225 per share payable on July 1,
2014. This represents fourteen consecutive years of dividend
increases since the Company first paid a dividend in 2001, with a
compound annual growth rate of 34% from 2009 when Horizon first
commenced production.  
OUTLOOK  
The Company forecasts 2014 production levels before royalties to
average between 537,000 and 574,000 bbl/d of crude oil and NGLs and
between 1,530 and 1,570 MMcf/d of natural gas. The 2014 production
guidance has been revised to reflect certain crude oil and natural
gas property acquisitions which have closed to date. Q2/14 production
guidance before royalties is forecast to average between 519,000 and
546,000 bbl/d of crude oil and NGLs and between 1,620 and 1,660
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, the
construction and future operations of the North West Redwater bitumen
upgrader and refinery, construction by third parties of new or
expansion of existing pipeline capacity or other means of
transportation of bitumen, crude oil, natural gas or synthetic crude
oil ("SCO") that the Company may be reliant upon to transport its
products to market 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 months ended March
31, 2014 and the MD&A and the audited consolidated financial
statements for the year ended December 31, 2013.  
All dollar amounts are referenced in millions of Canadian dollars,
except where noted otherwise. The Company's unaudited interim
consolidated financial statements for the period ended March 31, 2014
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 and depreciation, depletion and
amortization are 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 SCO.  
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 months ended March 31, 2014 in relation to the
first quarter of 2013 and the fourth 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, 2013, is available on SEDAR at
www.sedar.com, and on EDGAR at www.sec.gov. This MD&A is dated May 8,
2014. 
FINANCIAL HIGHLIGHTS  


 
 
($ millions, except per common share amounts)                               
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
                                                  2014       2013       2013
----------------------------------------------------------------------------
Product sales                               $    4,968 $    4,330 $    4,101
Net earnings                                $      622 $      413 $      213
  Per common share - basic                  $     0.57 $     0.38 $     0.19
    - diluted                               $     0.57 $     0.38 $     0.19
Adjusted net earnings from operations (1)   $      921 $      563 $      401
  Per common share - basic                  $     0.85 $     0.52 $     0.37
    - diluted                               $     0.85 $     0.52 $     0.37
Cash flow from operations (2)               $    2,146 $    1,782 $    1,571
  Per common share - basic                  $     1.97 $     1.64 $     1.44
    - diluted                               $     1.97 $     1.64 $     1.44
Capital expenditures, net of dispositions   $    1,893 $    2,091 $    1,736
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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       
                                           ---------------------------------
                                                Mar 31    Dec 31     Mar 31 
($ millions)                                      2014      2013       2013 
----------------------------------------------------------------------------
Net earnings as reported                    $      622 $     413  $     213 
Share-based compensation, net of tax (1)           143        65         71 
Unrealized risk management loss (gain), net                                 
 of tax (2)                                         38       (26)        51 
Unrealized foreign exchange loss, net of                                    
 tax (3)                                           118       111         78 
Realized foreign exchange gain on repayment                                 
 of US dollar debt securities, net of tax                                   
 (4)                                                 -         -        (12)
----------------------------------------------------------------------------
Adjusted net earnings from operations       $      921 $     563  $     401 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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 Company's 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% notes.  
Cash Flow from Operations 


 
 
                                                   Three Months Ended       
                                           ---------------------------------
                                                Mar 31    Dec 31     Mar 31 
($ millions)                                      2014      2013       2013 
----------------------------------------------------------------------------
Net earnings                                $      622 $     413  $     213 
Non-cash items:                                                             
  Depletion, depreciation and amortization       1,011     1,272      1,142 
  Share-based compensation                         143        65         71 
  Asset retirement obligation accretion             45        46         42 
  Unrealized risk management loss (gain)            49       (30)        62 
  Unrealized foreign exchange loss                 118       111         78 
  Realized foreign exchange gain on                                         
   repayment of US dollar debt securities    
        -         -        (12)
  Equity loss from joint venture                     1         1          2 
  Deferred income tax expense (recovery)           157       (96)       (27)
----------------------------------------------------------------------------
Cash flow from operations                   $    2,146 $   1,782  $   1,571 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS  
Net earnings for the first quarter of 2014 were $622 million compared
with $213 million for the first quarter of 2013 and $413 million for
the fourth quarter of 2013. Net earnings for the first quarter of
2014 included net after-tax expenses of $299 million compared with
$188 million for the first quarter of 2013 and $150 million for the
fourth quarter of 2013 related to the effects of share-based
compensation, risk management activities, and fluctuations in foreign
exchange rates including the impact of a realized foreign exchange
gain on repayment of long-term debt. Excluding these items, adjusted
net earnings from operations for the first quarter of 2014 were $921
million compared with $401 million for the first quarter of 2013 and
$563 million for the fourth quarter of 2013.  
The increase in adjusted net earnings for the first quarter of 2014
from the first quarter of 2013 was primarily due to: 
- higher crude oil and NGLs and natural gas netbacks in the North
America segment;  
- higher SCO sales volumes and realized SCO prices in the Oil Sands
Mining and Upgrading segment;  
- lower depletion, depreciation and amortization expense; and  
- the impact of a weaker Canadian dollar relative to the US dollar;  
partially offset by: 
- lower crude oil sales volumes in the Offshore Africa segment.  
The increase in adjusted net earnings for the first quarter of 2014
from the fourth quarter of 2013 was primarily due to: 
- higher crude oil and NGLs and natural gas netbacks in the North
America segment;  
- higher realized SCO prices;  
- lower depletion, depreciation and amortization expense; and  
- the impact of a weaker Canadian dollar relative to the US dollar;  
partially offset by: 
- lower crude oil sales volumes in the Offshore Africa segment.  
The impacts of share-based compensation, risk management activities
and fluctuations 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 first quarter of 2014 was $2,146
million compared with $1,571 million for the first quarter of 2013
and $1,782 million for the fourth 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 first quarter of 2014
averaged 684,647 BOE/d and was comparable with the first quarter of
2013 and increased 1% from 677,242 BOE/d for the fourth 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       Mar 31     Dec 31     Sep 30     Jun 30
 share amounts)                        2014       2013       2013       2013
----------------------------------------------------------------------------
Product sales                    $    4,968 $    4,330 $    5,284 $    4,230
Net earnings                     $      622 $      413 $    1,168 $      476
Net earnings per common share                                               
  - basic                        $     0.57 $     0.38 $     1.07 $     0.44
  - diluted                      $     0.57 $     0.38 $     1.07 $     0.44
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
($ millions, except per common       Mar 31     Dec 31     Sep 30     Jun 30
 share amounts)                        2013       2012       2012       2012
----------------------------------------------------------------------------
Product sales                    $    4,101 $    4,059 $    3,978 $    4,187
Net earnings                     $      213 $      352 $      360 $      753
Net earnings per common share                                               
  - basic                        $     0.19 $     0.32 $     0.33 $     0.68
  - diluted                      $     0.19 $     0.32 $     0.33 $     0.68
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 the 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
strong 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 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, 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, fluctuations in depletion,
depreciation and amortization expense in the North Sea due to the
planned decommissioning of the Murchison platform, 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 denomina
ted 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.  
- Gains on corporate acquisition/disposition of properties -
Fluctuations due to the recognition of gains on corporate
acquisitions/dispositions in the third quarter of 2013.  
BUSINESS ENVIRONMENT 


 
 
                                                   Three Months Ended       
                                           ---------------------------------
                                               Mar 31     Dec 31     Mar 31 
                                                 2014       2013       2013 
----------------------------------------------------------------------------
WTI benchmark price (US$/bbl)               $   98.61  $   97.50  $   94.34 
Dated Brent benchmark price (US$/bbl)       $  108.20  $  109.29  $  112.43 
WCS blend differential from WTI (US$/bbl)   $   23.27  $   32.21  $   31.79 
WCS blend differential from WTI (%)                24%        33%        34%
SCO price (US$/bbl)                         $   96.45  $   88.37  $   95.24 
Condensate benchmark price (US$/bbl)        $  102.53  $   94.30  $  107.18 
NYMEX benchmark price (US$/MMBtu)           $    4.89  $    3.63  $    3.35 
AECO benchmark price (C$/GJ)                $    4.52  $    2.99  $    2.92 
US/Canadian dollar average exchange rate                                    
 (US$)                                      $  0.9064  $  0.9529  $  0.9917 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Commodity Prices  
Crude oil sales contracts in the North America segment are typically
based on WTI benchmark pricing. WTI averaged US$98.61 per bbl for the
first quarter of 2014, an increase of 5% from US$94.34 per bbl for
the first quarter of 2013, and was comparable with the fourth quarter
of 2013.  
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$108.20 per bbl for the first
quarter of 2014, a decrease of 4% from US$112.43 per bbl for the
first quarter of 2013, and was comparable with the fourth quarter of
2013.  
WTI and Brent pricing continued to reflect volatility in supply and
demand factors and geopolitical events. The Brent differential from
WTI tightened for the first quarter of 2014 from the comparable
periods in 2013 due to a continued debottlenecking of logistical
constraints from Cushing to the US Gulf Coast.  
The WCS Heavy Differential averaged 24% for the first quarter of
2014, compared with 34% for the first quarter of 2013, and 33% for
the fourth quarter of 2013. The WCS Heavy Differential tightened in
the first quarter of 2014 from the comparable periods due to the
reinstatement of third party refinery operations, increased demand as
a result of third party refinery expansion and higher refinery
utilization in the first quarter of 2014. To partially mitigate its
exposure to fluctuating heavy crude oil differentials, as at March
31, 2014, the Company entered into physical crude oil sales contracts
with weighted average fixed WCS differentials as follows: 10,000
bbl/d in the second quarter of 2014 at US$21.69 per bbl; and 10,000
bbl/d in the third and fourth quarters of 2014 at US$20.81 per bbl.
Subsequent to March 31, 2014, the WCS Heavy Differential narrowed in
April 2014 to average US$22.47 per bbl and in May 2014 to average
US$19.07 per bbl.  
The SCO price averaged US$96.45 per bbl for the first quarter of
2014, comparable with the first quarter of 2013, and increased 9%
from US$88.37 per bbl for the fourth quarter of 2013. The increase in
SCO pricing for the first quarter of 2014 from the fourth quarter of
2013 was primarily due to an increase in demand as well as tightening
differentials from WTI benchmark pricing as a result of pipeline
constraints being alleviated from Cushing to the US Gulf Coast.  
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$4.89 per MMBtu for the first
quarter of 2014, an increase of 46% from US$3.35 per MMBtu for the
first quarter of 2013, and an increase of 35% from US$3.63 per MMBtu
for the fourth quarter of 2013.  
AECO natural gas prices for the first quarter of 2014 averaged $4.52
per GJ, an increase of 55% from $2.92 per GJ for the first quarter of
2013, and an increase of 51% from $2.99 per GJ for the fourth quarter
of 2013.  
Natural gas prices increased for the first quarter of 2014 from the
comparable periods due to increased winter weather related natural
gas demand. The colder than normal winter resulted in natural gas
storage inventories falling to below five-year lows in the US and
Canada as at March 31, 2014.  
DAILY PRODUCTION, before royalties 


 
 
                                                  Three Months Ended        
                                           ---------------------------------
                                               Mar 31     Dec 31     Mar 31 
                                                 2014       2013       2013 
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)                                                  
North America - Exploration and Production    348,187    332,231    345,489 
North America - Oil Sands Mining and                                        
 Upgrading                                    113,095    112,273    108,782 
North Sea                                      16,715     20,155     18,774 
Offshore Africa                                10,791     13,379     16,112 
----------------------------------------------------------------------------
                                              488,788    478,038    489,157 
----------------------------------------------------------------------------
Natural gas (MMcf/d)                                                        
North America                                   1,147      1,165      1,125 
North Sea                                           7          7          1 
Offshore Africa                                    21         23         24 
----------------------------------------------------------------------------
                                                1,175      1,195      1,150 
----------------------------------------------------------------------------
Total barrels of oil equivalent (BOE/d)       684,647    677,242    680,844 
----------------------------------------------------------------------------
Product mix                                                                 
Light and medium crude oil and NGLs                15%        16%        15%
Pelican Lake heavy crude oil                        7%         7%         5%
Primary heavy crude oil                            20%        20%        20%
Bitumen (thermal oil)                              12%        11%        16%
Synthetic crude oil                                17%        17%        16%
Natural gas                                        29%        29%        28%
----------------------------------------------------------------------------
Percentage of product sales (1)                                             
(excluding Midstream revenue)                                               
Crude oil and NGLs                                 86%        89%        89%
Natural gas                                        14%        11%        11%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Net of blending costs and excluding risk management activities.  
DAILY PRODUCTION, net of royalties 


 
 
                                                   Three Months Ended       
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
                                                  2014       2013       2013
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)                                                  
North America - Exploration and Production     280,826    285,594    289,992
North America - Oil Sands Mining and                                        
 Upgrading                                     106,891    106,358    104,203
North Sea                                       16,662     20,106     18,706
Offshore Africa                                  9,762     11,351     13,603
------------------------------------------------------------------
----------
                                               414,141    423,409    426,504
----------------------------------------------------------------------------
Natural gas (MMcf/d)                                                        
North America                                    1,017      1,101      1,092
North Sea                                            7          7          1
Offshore Africa                                     18         19         20
----------------------------------------------------------------------------
                                                 1,042      1,127      1,113
----------------------------------------------------------------------------
Total barrels of oil equivalent (BOE/d)        587,737    611,245    612,062
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The Company's business approach is to maintain large project
inventories and production diversification among each of the
commodities it produces; namely light and medium crude oil and NGLs,
primary heavy crude oil, Pelican Lake heavy crude oil, bitumen
(thermal oil), SCO and natural gas.  
Crude oil and NGLs production for the first quarter of 2014 averaged
488,788 bbl/d, comparable with the first quarter of 2013 and
increased 2% from 478,038 bbl/d for the fourth quarter of 2013. The
increase in production for the first quarter of 2014 from the fourth
quarter of 2013 was due to increased production in the North America
segment, primarily related to the impact of a strong heavy crude oil
drilling program, as well as the impact of strong and reliable
production in Horizon, partially offset by lower production in North
Sea and Offshore Africa. Crude oil and NGLs production in the first
quarter of 2014 was within the Company's previously issued guidance
of 469,000 to 495,000 bbl/d.  
Natural gas production for the first quarter of 2014 increased 2% to
1,175 MMcf/d from 1,150 MMcf/d for the first quarter of 2013 and
decreased 2% from 1,195 MMcf/d for the fourth quarter of 2013. The
increase in natural gas production from the first quarter of 2013 was
primarily a result of the completion of the Septimus drilling program
and plant facility expansion in the third quarter of 2013, as well as
the completion of minor acquisitions during 2013. The decrease in
natural gas production from the fourth quarter of 2013 was primarily
a result of normal production declines as the Company allocated
capital to higher return crude oil projects. Natural gas production
in the first quarter of 2014 was within the Company's previously
issued guidance of 1,166 to 1,186 MMcf/d.  
For 2014, annual production guidance is targeted to average between
537,000 and 574,000 bbl/d of crude oil and NGLs and between 1,530 and
1,570 MMcf/d of natural gas. Second quarter 2014 production guidance
is targeted to average between 519,000 and 546,000 bbl/d of crude oil
and NGLs and between 1,620 and 1,660 MMcf/d of natural gas.  
North America - Exploration and Production  
For the first quarter of 2014, crude oil and NGLs production averaged
348,187 bbl/d, comparable with the first quarter of 2013 and
increased 5% from 332,231 bbl/d for the fourth quarter of 2013. The
increase for the first quarter of 2014 from the fourth quarter of
2013 reflected strong production growth across the asset base,
including heavy crude oil. First quarter 2014 production of crude oil
and NGLs was within the Company's previously issued guidance of
335,000 to 351,000 bbl/d. Second quarter 2014 production guidance is
targeted to average between 378,000 and 396,000 bbl/d for crude oil
and NGLs.  
Natural gas production increased 2% to 1,147 MMcf/d for the first
quarter of 2014 compared with 1,125 MMcf/d in the first quarter of
2013 and decreased 2% from 1,165 MMcf/d for the fourth quarter of
2013. The increase in natural gas production for the first quarter of
2014 from the first quarter of 2013 was primarily a result of the
completion of the Septimus drilling program and plant facility
expansion in the third quarter of 2013, as well as the completion of
minor acquisitions during 2013. The decrease in natural gas
production from the fourth quarter of 2013 was primarily a result of
normal production declines as the Company allocated capital to higher
return crude oil projects.  
North America - Oil Sands Mining and Upgrading  
For the first quarter of 2014, SCO production increased 4% to 113,095
bbl/d from 108,782 bbl/d for the first quarter of 2013 and increased
1% from 112,273 bbl/d for the fourth quarter of 2013. Production
increased for the first quarter of 2014 from the comparable periods,
reflecting a continued focus on reliable and efficient operations.
First quarter 2014 production of SCO was within the Company's
previously issued guidance of 108,000 to 115,000 bbl/d. Second
quarter 2014 production guidance is targeted to average between
114,000 and 119,000 bbl/d.  
North Sea  
First quarter 2014 crude oil production decreased 11% to 16,715 bbl/d
from 18,774 bbl/d for the first quarter of 2013, and decreased 17%
from 20,155 bbl/d for the fourth quarter of 2013. The decrease in
production for the first quarter of 2014 from the comparable periods
was primarily due to the cessation of production of approximately
1,300 bbl/d related to the planned decommissioning of the Murchison
platform, unplanned downtime on the Tiffany platform, and natural
field declines in other North Sea fields. The Company commenced
drilling in the Ninian field late in the fourth quarter of 2013 with
expected production in the second quarter of 2014.  
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 has been
repaired, is back in the field and is currently being tied in to the
subsea system, with production targeted early in the third quarter of
2014.  
Offshore Africa  
First quarter 2014 crude oil production averaged 10,791 bbl/d,
decreasing 33% from 16,112 bbl/d for the first quarter of 2013 and
decreasing 19% from 13,379 bbl/d for the fourth quarter of 2013. The
decrease in production volumes for the first quarter of 2014 was due
to a temporary shut in of the Baobab field in December 2013 due to a
FPSO mooring line failure and natural field declines. Turnaround
activities were advanced into this timeframe and production in the
Baobab field was reinstated in late January 2014. The Company
successfully completed the permanent repairs on the mooring lines in
March 2014.  
International Guidance  
The Company's North Sea and Offshore Africa first quarter 2014 crude
oil production was 27,506 bbl/d and was within the Company's
previously issued guidance of 26,000 to 29,000 bbl/d. Second quarter
2014 production guidance is targeted to average between 27,000 and
31,000 bbl/d of crude oil. 
Crude Oil Inventory Volumes  
The Company recognizes revenue on its crude oil production when title
transfers to the customer and delivery has taken place. Revenue has
not been recognized on crude oil volumes that were stored in various
tanks, pipelines, or FPSOs, as follows: 


 
 
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
(bbl)                                             2014       2013       2013
----------------------------------------------------------------------------
North America - Exploration and Production   1,069,537    830,673    811,181
North America - Oil Sands Mining and                                        
 Upgrading (SCO)                             1,693,887  1,550,857  1,334,054
North Sea                                      311,457    385,073    409,333
Offshore Africa                              1,156,700    185,476    829,793
----------------------------------------------------------------------------
                                             4,231,581  2,952,079  3,384,361
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION                           
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
                                                  2014       2013       2013
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)                                              
Sales price (2)                             $    79.68 $    69.38 $    60.87
Transportation                                    2.49       1.84       2.37
-------------------------------
---------------------------------------------
Realized sales price, net of transportation      77.19      67.54      58.50
Royalties                                        14.05       8.82       8.76
Production expense                               19.18      18.59      17.56
----------------------------------------------------------------------------
Netback                                     $    43.96 $    40.13 $    32.18
----------------------------------------------------------------------------
Natural gas ($/Mcf) (1)                                                     
Sales price (2)                             $     5.69 $     3.62 $     3.51
Transportation                                    0.30       0.28       0.29
----------------------------------------------------------------------------
Realized sales price, net of transportation       5.39       3.34       3.22
Royalties                                         0.62       0.21       0.12
Production expense                                1.61       1.37       1.53
----------------------------------------------------------------------------
Netback                                     $     3.16 $     1.76 $     1.57
----------------------------------------------------------------------------
Barrels of oil equivalent ($/BOE) (1)                                       
Sales price (2)                             $    63.14 $    53.30 $    47.90
Transportation                                    2.29       1.83       2.21
----------------------------------------------------------------------------
Realized sales price, net of transportation      60.85      51.47      45.69
Royalties                                        10.42       6.23       6.05
Production expense                               15.82      15.04      14.74
----------------------------------------------------------------------------
Netback                                     $    34.61 $    30.20 $    24.90
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Amounts expressed on a per unit basis are based on sales volumes.  
(2) Net of blending costs and excluding risk management activities.  
PRODUCT PRICES - EXPLORATION AND PRODUCTION 


 
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
                                                  2014       2013       2013
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)(2)                                           
North America                               $    77.54 $    62.70 $    55.68
North Sea                                   $   121.38 $   113.84 $   114.28
Offshore Africa                             $        - $   108.25 $   113.70
Company average                             $    79.68 $    69.38 $    60.87
 
Natural gas ($/Mcf) (1)(2)                                                  
North America                               $     5.56 $     3.46 $     3.37
North Sea                                   $     6.05 $     5.05 $     3.65
Offshore Africa                             $    12.18 $    11.13 $    10.24
Company average                             $     5.69 $     3.62 $     3.51
 
Company average ($/BOE) (1)(2)              $    63.14 $    53.30 $    47.90
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Amounts expressed on a per unit basis are based on sales volumes.  
(2) Net of blending costs and excluding risk management activities.  
North America  
North America realized crude oil prices averaged $77.54 per bbl for
the first quarter of 2014 and increased 39% compared with $55.68 per
bbl for the first quarter of 2013 and increased 24% compared with
$62.70 per bbl for the fourth quarter of 2013. The increase in
realized crude oil prices for the first quarter of 2014 from the
comparable periods was due to higher WTI benchmark pricing,
tightening WCS Heavy Differentials and the impact of a weaker
Canadian dollar relative to the US dollar. The Company continues to
focus on its crude oil blending marketing strategy and in the first
quarter of 2014 contributed approximately 172,000 bbl/d of heavy
crude oil blends to the WCS stream.  
North America realized natural gas prices increased 65% to average
$5.56 per Mcf for the first quarter of 2014 compared with $3.37 per
Mcf in the first quarter of 2013, and increased 61% compared with
$3.46 per Mcf for the fourth quarter of 2013. The increase in
realized natural gas prices for the first quarter of 2014 from the
comparable periods was primarily due to increased winter weather
related natural gas demand resulting in natural gas storage
inventories falling to below five-year lows in the US and Canada as
at March 31, 2014. 
Comparisons of the prices received in North America Exploration and
Production by product type were as follows: 


 
 
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
(Quarterly Average)                               2014       2013       2013
----------------------------------------------------------------------------
Wellhead Price(1) (2)                                                       
Light and medium crude oil and NGLs ($/bbl) $    83.57 $    70.91 $    73.77
Pelican Lake heavy crude oil ($/bbl)        $    79.94 $    60.19 $    54.41
Primary heavy crude oil ($/bbl)             $    77.78 $    61.75 $    51.45
Bitumen (thermal oil) ($/bbl)               $    69.73 $    57.97 $    50.42
Natural gas ($/Mcf)                         $     5.56 $     3.46 $     3.37
-------------------------------------------------
---------------------------
----------------------------------------------------------------------------

(1) Amounts expressed on a per unit basis are based on sales volumes.  
(2) Net of blending costs and excluding risk management activities.  
North Sea  
Realized crude oil prices increased 6% to average $121.38 per bbl for
the first quarter of 2014 from $114.28 per bbl for the first quarter
of 2013, and increased 7% from $113.84 per bbl for the fourth quarter
of 2013. The increase in realized crude oil prices for the first
quarter of 2014 from the comparable periods was primarily the result
of the timing of liftings and the impact of a weaker Canadian dollar
relative to the US dollar. 
Offshore Africa  
Due to the timing of scheduled liftings from the various fields, the
Company had no crude oil liftings during the first quarter of 2014.
Accordingly, no crude oil revenue was recognized. Realized crude oil
prices averaged $113.70 per bbl for the first quarter of 2013 and
$108.25 per bbl for the fourth quarter of 2013. 
ROYALTIES - EXPLORATION AND PRODUCTION 


 
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
                                                  2014       2013       2013
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)                                              
North America                               $    14.75 $     8.66 $     8.65
North Sea                                   $     0.38 $     0.28 $     0.41
Offshore Africa                             $        - $    16.41 $    17.71
Company average                             $    14.05 $     8.82 $     8.76
 
Natural gas ($/Mcf) (1)                                                     
North America                               $     0.60 $     0.17 $     0.09
Offshore Africa                             $     2.06 $     2.04 $     1.57
Company average                             $     0.62 $     0.21 $     0.12
 
Company average ($/BOE) (1)                 $    10.42 $     6.23 $     6.05
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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 first
quarter of 2014 reflected movements in benchmark commodity prices and
the fluctuations of the WCS Heavy Differential.  
Crude oil and NGLs royalties averaged approximately 20% of product
sales for the first quarter of 2014 compared with 16% for the first
quarter of 2013 and 14% for the fourth quarter of 2013. The increase
in royalties in the first quarter of 2014 from the comparable periods
was primarily due to the increase in realized crude oil prices
. Crude
oil and NGLs royalties per bbl are anticipated to average 19% to 21%
of product sales for 2014.  
Natural gas royalties averaged approximately 11% of product sales for
the first quarter of 2014 compared with 3% for the first quarter of
2013 and 5% for the fourth quarter of 2013. The increase in natural
gas royalty rates in the first quarter of 2014 from the comparable
periods was primarily due to the increase in realized natural gas
prices. Natural gas royalties are anticipated to average 10% to 11%
of product sales for 2014.  
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 first quarter of 2014 and related to natural gas sales
only. Royalty rates as a percentage of product sales averaged
approximately 16% for the first quarter of 2013 and 15% for the
fourth quarter of 2013.  
Offshore Africa royalty rates are anticipated to average 4.5% to 6.5%
of product sales for 2014. 
PRODUCTION EXPENSE - EXPLORATION AND PRODUCTION 


 
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
                                                  2014       2013       2013
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl) (1)                                              
North America                               $    16.31 $    14.46 $    14.61
North Sea                                   $    75.51 $    65.41 $    74.65
Offshore Africa                             $        - $    29.31 $    25.72
Company average                             $    19.18 $    18.59 $    17.56
 
Natural gas ($/Mcf) (1)                                                     
North America                               $     1.54 $     1.32 $     1.52
North Sea                                   $     5.83 $     4.81 $     3.77
Offshore Africa                             $     3.64 $     2.73 $     2.24
Company average                             $     1.61 $     1.37 $     1.53
 
Company average ($/BOE) (1)                 $    15.82 $    15.04 $    14.74
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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 first
quarter of 2014 increased 12% to $16.31 per bbl from $14.61 per bbl
for the first quarter of 2013 and increased 13% from $14.46 per bbl
for the fourth quarter of 2013. The increase in production expense
for the first quarter of 2014 from the comparable periods was
primarily the result of higher energy costs, as well as higher
servicing costs related to heavy oil activities, and cyclic timing of
thermal oil production. North America crude oil and NGLs production
expense is anticipated to average $13.00 to $15.00 per bbl for 2014.  
North America natural gas production expense for the first quarter of
2014 averaged $1.54 per Mcf, comparable with the first quarter of
2013 and increased 17% from $1.32 per Mcf for the fourth quarter of
2013. Natural gas production expense increased for the first quarter
of 2014 from the fourth quarter of 2013 due to lower production
volumes along with the impact of seasonal conditions. North America
natural gas production expense is anticipated to average $1.35 to
$1.45 per Mcf for 2014. 
North Sea  
North Sea crude oil production expense for the first quarter of 2014
averaged $75.51 per bbl, comparable with the first quarter of 2013
and increased 15% from $65.41 per bbl for the fourth quarter of 2013.
Production expense increased on a per barrel basis from the fourth
quarter of 2013 due to the impact of the cessation of production from
the Murchison platform in the first quarter of 2014, production
declines on relatively fixed costs in other North Sea fields and the
impact of a weaker Canadian dollar. North Sea crude oil production
expense is anticipated to average $60.00 to $64.00 per bbl for 2014
as new drilling activities are expected to result in additional
production from the Ninian fields, and as the Banff FPSO is targeted
to return to service early in the third quarter of 2014.  
Offshore Africa  
As there were no crude oil liftings during the first quarter of 2014,
no crude oil production expense was recognized during the first
quarter of 2014. Offshore Africa crude oil production expense
averaged $25.72 per bbl for the first quarter of 2013 and $29.31 per
bbl for the fourth quarter of 2013. Offshore Africa crude oil
production expense is anticipated to average $38.50 to $42.50 per bbl
for 2014 due to timing of liftings from various fields, which have
different cost structures.  
DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND
PRODUCTION 


 
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
                                                  2014       2013       2013
----------------------------------------------------------------------------
Expense ($ millions)                        $      879 $    1,133 $    1,023
  $/BOE (1)                                 $    17.55 $    21.20 $    19.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Amounts expressed on a per unit basis are based on sales volumes.  
Depletion, depreciation and amortization expense decreased for the
first quarter of 2014 from the comparable periods due to the increase
in the North America proved reserves, lower sales volumes in Offshore
Africa and lower depletion, depreciation and amortization expense
from the Murchison field in the North Sea due to the cessation of
production.  
ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND
PRODUCTION 


 
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
                                                  2014       2013       2013
----------------------------------------------------------------------------
Expense ($ millions)                        $       33 $       38 $       34
  $/BOE (1)                                 $     0.67 $     0.71 $     0.66
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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  
During the first quarter of 2014 the Company continued to focus on
reliable and efficient operations, leading to production of 113,095
bbl/d, which was within stated guidance.  
PRODUCT PRICES, ROYALTIES AND TRANSPORTATION - OIL SANDS MINING AND
UPGRADING 


 
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
($/bbl) (1)                                       2014       2013       2013
------------------------------------------------------------
----------------
SCO sales price                             $   107.82 $    92.05 $    96.19
Bitumen value for royalty purposes (2)      $    66.27 $    55.45 $    60.47
Bitumen royalties (3)                       $     5.06 $     5.06 $     3.81
Transportation                              $     1.96 $     1.51 $     1.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Amounts expressed on a per unit basis are based on sales volumes.  
(2) Calculated as the quarterly average of the bitumen valuation
methodology price.  
(3) Calculated based on actual bitumen royalties expensed during the
period; divided by the corresponding SCO sales volumes.  
Realized SCO sales prices averaged $107.82 per bbl for the first
quarter of 2014, an increase of 12% compared with $96.19 per bbl for
the first quarter of 2013 and an increase of 17% compared with $92.05
per bbl for the fourth quarter of 2013, reflecting benchmark pricing,
prevailing differentials and the impact of a weaker Canadian dollar
relative to the US dollar.  
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      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
($ millions)                                      2014       2013       2013
----------------------------------------------------------------------------
Cash production costs, excluding natural                                    
 gas costs                                  $      375 $      362 $      349
Natural gas costs                                   37         27         28
----------------------------------------------------------------------------
Total cash production costs                 $      412 $      389 $      377
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
($/bbl) (1)                                       2014       2013       2013
----------------------------------------------------------------------------
Cash production costs, excluding natural                                    
 gas costs                                  $    37.39 $    36.31 $    36.95
Natural gas costs                                 3.72       2.74       2.98
----------------------------------------------------------------------------
Total cash production costs                 $    41.11 $    39.05 $    39.93
----------------------------------------------------------------------------
Sales (bbl/d)                                  111,506    108,163    105,000
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Amounts expressed on a per unit basis are based on sales volumes.  
Cash production costs for the first quarter of 2014 averaged $41.11
per bbl, an increase of 3% compared with $39.93 per bbl for the first
quarter of 2013 and an increase of 5% compared with $39.05 per bbl
for the fourth quarter of 2013 primarily reflecting higher energy
costs including natural gas and mine diesel fuel. Cash production
costs are anticipated to average $36.00 to $39.00 per bbl for 2014.  
DEPLETION, DEPRECIATION AND AMORTIZATION - OIL SANDS MINING AND
UPGRADING 


 
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
($ millions)                                      2014       2013       2013
----------------------------------------------------------------------------
Depletion, depreciation and amortization    $      130 $      137 $      117
  $/bbl (1)                                 $    12.95 $    13.75 $    12.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Amounts expressed on a per unit basis are based on sales volumes.  
Depletion, depreciation and amortization expense for the first
quarter of 2014 increased compared to the first quarter of 2013 due
to higher sales volumes. Depletion, depreciation and amortization
expense for the first quarter of 2014 was comparable to the fourth
quarter of 2013.  
ASSET RETIREMENT OBLIGATION ACCRETION - OIL SANDS MINING AND
UPGRADING 


 
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
($ millions)                                      2014       2013       2013
----------------------------------------------------------------------------
Expense                                     $       12 $        8 $        8
  $/bbl (1)                                 $     1.17 $     0.85 $     0.90
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
($ millions)                                      2014       2013       2013
----------------------------------------------------------------------------
Revenue                                     $       31 $       26 $       27
Production expense                                   9          8          8
----------------------------------------------------------------------------
Midstream cash flow                                 22         18         19
Depreciation                                         2          2          2
Equity loss from joint venture                       1          1          2
----------------------------------------------------------------------------
Segment earnings before taxes               $       19 $       15 $       15
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Midstream operating results were consistent with the comparable
periods.  
The Company has a 50% interest in the North West Redwater Partnership
("Redwater Partnership"). Redwater Partnership 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 ("APMC"), 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 Partnership and its partners.  
As at March 31, 2014, Redwater Partnership had interim borrowings of
$955 million under credit facilities totaling $1,200 million maturing
on November 28, 2014. These facilities are secured by a floating
charge on the assets of Redwater Partnership with a mandatory
repayment required from future financing proceeds. At maturity or at
such later date as mutually agreed to by the lenders and Redwater
Partnership, the Company will be obligated to repay its 25% pro rata
share of any amount outstanding under the facility. As at May 7,
2014, interim borrowings under the facilities were $883 million.  
In April 2014, Redwater Partnership, the Company and APMC amended
certain terms of the processing agreements. In conjunction with these
amendments, the Company, along with APMC, each committed to provide
additional funding up to $350 million to attain Project completion
based on the revised Project cost estimate of approximately $8,500
million. The additional funding is to be in the form of subordinated
debt bearing interest at prime plus 6%, which is anticipated to form
part of the equity toll. As at May 7, 2014, the Company and APMC had
each provided $113 million of funding of subordinated debt. Should
final Project costs exceed the revised cost estimate, the Company and
APMC have agreed, subject to the Company being able to meet certain
funding conditions, to fund any shortfall in available third party
commercial lending required to attain Project completion.  
Redwater Partnership has entered into various agreements related to
the engineering, procurement and construction of the Project. These
contracts can be cancelled by Redwater Partnership upon notice
without penalty, subject to the costs incurred up to and in respect
of the cancellation.  
ADMINISTRATION EXPENSE 


 
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
($ millions)                                      2014       2013       2013
----------------------------------------------------------------------------
Expense                                     $       90 $       93 $       79
  $/BOE (1)                                 $     1.49 $     1.47 $     1.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Amounts expressed on a per unit basis are based on sales volumes.  
Administration expense for the first quarter of 2014 increased from
the first quarter of 2013 primarily due to higher staffing and
general corporate costs, and was comparable with the fourth quarter
of 2013.  
SHARE-BASED COMPENSATION  


 
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
($ millions)                                      2014       2013       2013
----------------------------------------------------------------------------
Expense                                     $      143 $       65 $       71
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The Company's stock option plan provides current employees with the
right to receive common shares or a cash payment in exchange for
stock options surrendered.  
The Company recorded a $143 million share-based compensation expense
for the three months ended March 31, 2014, 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 three
months ended March 31, 2014, the Company capitalized $26 million of
share-based compensation expense to property, plant and equipment in
the Oil Sands Mining and Upgrading segment (March 31, 2013 - $11
million expense).  
For the three months ended March 31, 2014, the Company paid $4
million for stock options surrendered for cash settlement (March 31,
2013 - $1 million). 
INTEREST AND OTHER FINANCING EXPENSE 


 
 
                                                   Three Months Ended       
                                           ---------------------------------
                                               Mar 31     Dec 31     Mar 31 
($ millions, except per BOE amounts)             2014       2013       2013 
----------------------------------------------------------------------------
Expense, gross                              $     115  $     113  $     113 
Less: capitalized interest                         47         53         36 
----------------------------------------------------------------------------
Expense, net                                $      68  $      60  $      77 
  $/BOE (1)                                 $    1.13  $    0.94  $    1.27 
Average effective interest rate                   4.3%       4.4%       4.5%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Amounts expressed on a per unit basis are based on sales volumes.  
Gross interest and other financing expense for the first quarter of
2014 was consistent with the comparable periods. Capitalized interest
of $47 million for the three months ended March 31, 2014 was
primarily related to the Horizon Phase 2/3 expansion.  
The Company's average effective interest rate for first quarter of
2014 decreased from the first quarter of 2013 primarily due to an
increase in the utilization of the lower cost US commercial paper
program that was implemented in March 2013 as well as the repayment
of $400 million of 4.50% medium-term notes and US$400 million of
5.15% notes during the first quarter of 2013. The Company's average
effective interest rate for the first quarter of 2014 was comparable
with the fourth quarter of 2013. 
RISK MANAGEMENT ACTIVITIES  
The Company utilizes various derivative financial instruments to
manage its commodity price, interest rate and foreign currency
exposures. These derivative financial instruments are not intended
for trading or speculative purposes. 


 
 
                                                   Three Months Ended       
                                           ---------------------------------
                                               Mar 31     Dec 31     Mar 31 
($ millions)                                     2014       2013       2013 
----------------------------------------------------------------------------
Crude oil and NGLs financial instruments    $       -  $       5  $       - 
Foreign currency contracts                        (75)       (41)       (83)
----------------------------------------------------------------------------
Realized gain                                     (75)       (36)       (83)
----------------------------------------------------------------------------
 
Crude oil and NGLs financial instruments           (3)       (10)        24 
Natural gas financial instruments                  45         (5)         - 
Foreign currency contracts                          7        (15)        38 
----------------------------------------------------------------------------
Unrealized loss (gain)                             49        (30)        62 
----------------------------------------------------------------------------
Net gain                                    $     (26) $     (66) $     (21)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Complete details related to outstanding derivative financial
instruments at March 31, 2014 are disclosed in note 13 to the
Company's unaudited interim consolidated financial statements.  
The Company recorded a net unrealized loss of $49 million ($38
million after-tax) on its risk management activities for the three
months ended March 31, 2014 (December 31, 2013 - unrealized gain of
$30 million; $26 million after-tax; March 31, 2013 - unrealized loss
of $62 million; $51 million after-tax). 
FOREIGN EXCHANGE 


 
 
                                                   Three Months Ended       
                                           ---------------------------------
                                               Mar 31      Dec 31    Mar 31 
($ millions)                                     2014        2013      2013 
----------------------------------------------------------------------------
Net realized (gain) loss                    $      (1) $        3 $     (32)
Net unrealized loss (1)                           118         111        78 
----------------------------------------------------------------------------
Net loss                                    $     117  $      114 $      46 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Amounts are reported net of the hedging effect of cross currency
swaps.  
The net realized foreign exchange gain for the three months ended
March 31, 2014 was primarily due to foreign exchange rate
fluctuations on settlement of working capital items denominated in US
dollars or UK pounds sterling. The net unrealized foreign exchange
loss for the three months ended March 31, 2014 was primarily related
to the impact of a weaker Canadian dollar with respect to US dollar
debt. The net unrealized loss for each of the periods presented
included the impact of cross currency swaps (three months ended March
31, 2014 - unrealized gain of $100 million, December 31, 2013 -
unrealized gain of $85 million, March 31, 2013 - unrealized gain of
$49 million). The US/Canadian dollar exchange rate at March 31, 2014
was US$0.9047 (December 31, 2013 - US$0.9402; March 31, 2013 -
US$0.9846). 
INCOME TAXES 


 
 
                                                   Three Months Ended       
                                           ---------------------------------
                                               Mar 31     Dec 31     Mar 31 
($ millions, except income tax rates)            2014       2013       2013 
----------------------------------------------------------------------------
North America (1)                           $     192  $     133  $     122 
North Sea                                         (15)         5         (7)
Offshore Africa                                     4         55         35 
PRT (recovery) expense- North Sea                 (61)         5        (13)
Other taxes                                         6          4          4 
----------------------------------------------------------------------------
Current income tax expense                        126        202        141 
----------------------------------------------------------------------------
Deferred income tax expense (recovery)             91        (36)        (4)
Deferred PRT expense (recovery) - North Sea        66        (60)       (23)
----------------------------------------------------------------------------
Deferred income tax expense (recovery)            157        (96)       (27)
----------------------------------------------------------------------------
                                            $     283  $     106  $     114 
----------------------------------------------------------------------------
Effective income tax rate on adjusted net                                   
 earnings from operations (2)                    23.5%      21.4%      28.1%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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.  
For 2014, based on forward commodity prices and the current
availability of tax pools, the Company expects to incur current
income tax expense of $950 million to $1,050 million in Canada and
recoveries of $95 million to $115 million in the North Sea and
Offshore Africa.  
NET CAPITAL EXPENDITURES (1) 


 
 
                                                    Three Months Ended      
                                           ---------------------------------
                                                Mar 31     Dec 31     Mar 31
($ millions)                                      2014       2013       2013
----------------------------------------------------------------------------
Exploration and Evaluation                                                  
Net expenditures                            $      117 $        7 $       77
----------------------------------------------------------------------------
Property, Plant and Equipment                                               
Net property acquisitions                          (4)         61         11
Well drilling, completion and equipping            641        600        555
Production and related facilities                  415        444        537
Capitalized interest and other (2)                  23         34         28
----------------------------------------------------------------------------
Net expenditures                                 1,075      1,139      1,131
----------------------------------------------------------------------------
Total Exploration and Production                 1,192      1,146      1,208
----------------------------------------------------------------------------
Oil Sands Mining and Upgrading                                              
Horizon Phase 2/3 construction costs               444        597        355
Sustaining capital                                  60         28         51
Turnaround costs                                     2          2         17
Capitalized interest and other (2)                  73         56         38
----------------------------------------------------------------------------
Total Oil Sands Mining and Upgrading               579        683        461
----------------------------------------------------------------------------
Midstream                                           25        185          5
Abandonments (3)                                    87         71         55
Head office                                         10          6          7
----------------------------------------------------------------------------
Total net capital expenditures              $    1,893 $    2,091 $    1,736
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment                                                                  
North America                               $    1,087 $    1,001 $    1,093
North Sea                                           88         95         85
Offshore Africa                                     17         50         30
Oil Sands Mining and Upgrading                     579        683        461
Midstream                                           25        185          5
Abandonments (3)                                    87         71         55
Head office                                         10          6          7
----------------------------------------------------------------------------
Total                                       $    1,893 $    2,091 $    1,736
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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 first quarter of 2014 were $1,893
million compared with $1,736 million for the first quarter of 2013
and $2,091 million for the fourth quarter of 2013.  
The increase in capital expenditures for the first quarter of 2014
from the first quarter of 2013 was primarily due to increased well
drilling and completions spending as well as Horizon Phase 2/3 site
construction activity partially offset by decreased production and
related facilities spending. The decrease in capital expenditures for
the first quarter of 2014 from the fourt
h quarter of 2013 was
primarily due to reduced capital spending in Horizon Phase 2/3 site
construction activity as well as lower Midstream pipeline activity,
partially offset by higher exploration and evaluation activities in
North America.  
During the first quarter of 2014, the Company entered into an
agreement to acquire certain producing Canadian crude oil and natural
gas properties, together with undeveloped land. In connection with
the agreement, the Company arranged an additional $1,000 million
unsecured non-revolving bank credit facility maturing March 2016 and
with terms similar to the Company's current syndicated credit
facilities, available upon closing. Subsequently, the Company
completed the acquisition of these properties on April 1, 2014, for
preliminary cash consideration of approximately $3,092 million,
subject to final closing adjustments. 
Drilling Activity (number of wells) 


 
 
                                                  Three Months Ended        
                                           ---------------------------------
                                               Mar 31     Dec 31     Mar 31 
                                                 2014       2013       2013 
----------------------------------------------------------------------------
Net successful natural gas wells                   25         11         15 
Net successful crude oil wells (1)                271        324        300 
Dry wells                                           3         13          5 
Stratigraphic test / service wells                330         54        305 
----------------------------------------------------------------------------
Total                                             629        402        625 
Success rate (excluding stratigraphic test                                  
 / service wells)                                  99%        96%        98%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Includes bitumen wells.  
North America  
North America, excluding Oil Sands Mining and Upgrading, accounted
for approximately 62% of the total capital expenditures for the three
months ended March 31, 2014 compared with approximately 66% for the
three months ended March 31, 2013.  
During the first quarter of 2014, the Company targeted 25 net natural
gas wells, including 11 wells in Northeast British Columbia, 13 wells
in Northwest Alberta and 1 well in Northern Plains. The Company also
targeted 274 net crude oil wells. The majority of these wells were
concentrated in the Company's Northern Plains region where 224
primary heavy crude oil wells, 11 bitumen (thermal oil) wells and 1
light crude oil well were drilled. Another 38 wells targeting light
crude oil were drilled outside the Northern Plains region.  
Overall thermal oil production for the first quarter of 2014 averaged
approximately 82,000 bbl/d compared with approximately 109,000 bbl/d
for the first quarter of 2013 and approximately 78,000 bbl/d for the
fourth quarter of 2013. Production volumes were in line with
expectations due to the cyclic nature of thermal oil production at
Primrose and the ramp up of production at Kirby South.  
In the second quarter of 2013, the Company discovered bitumen
emulsion at surface in areas of the Primrose field. The Company
continues to work with the regulator on the causation review of the
bitumen emulsion seepage. The Company's near term steaming plan at
Primrose has been modified, with steaming being reduced in certain
areas. 
The next planned phase of the Company's in situ Oil Sands assets
expansion is the Kirby South Project. Site construction is complete
and first steam injection was achieved in September 2013. As at March
31, 2014, 25 well pairs had been fully converted to the production
stage.   
Development of the tertiary recovery conversion projects at Pelican
Lake continued and 3 horizontal injection wells were drilled during
the first quarter of 2014. Pelican Lake production averaged
approximately 48,000 bbl/d for the first quarter of 2014 compared
with 38,000 bbl/d for the first quarter of 2013 and 46,000 bbl/d for
the fourth quarter of 2013.  
In order to expand its pipeline infrastructure the Company has
participated in the expansion of the Cold Lake pipeline with
construction anticipated to be completed by 2016.  
For the second quarter of 2014, the Company's overall planned
drilling activity in North America is expected to be 139 net crude
oil wells, 3 net bitumen wells and 14 net natural gas wells,
excluding stratigraphic and service wells. 
Oil Sands Mining and Upgrading  
Phase 2/3 expansion activity in the first quarter of 2014 was focused
on field construction of the gas recovery unit, sulphur recovery
unit, butane treatment unit, coker expansion, tank farms, cooling
water tower, tailings, hydrotransport, froth treatment, tailings
pumphouse, and extraction trains 3 and 4, along with engineering
related to the froth treatment plants, extraction retrofit of trains
1 and 2, hydrogen unit, hydrotreater unit, vacuum distillation unit
and distillation recovery unit. 
North Sea  
The Company commenced drilling in the Ninian field late in the fourth
quarter of 2013 with expected production in the second quarter of
2014. The decommissioning activities at the Murchison platform
commenced in the fourth quarter of 2013 and the Company estimates the
decommissioning efforts will continue for approximately 5 years.  
Offshore Africa  
During the fourth quarter of 2013, the Company contracted a drilling
rig for a 6 gross well drilling program at the Baobab field in Cote
d'Ivoire. This rig is expected to arrive in country no later than the
first quarter of 2015. In April 2014, at the Espoir field, the
Company contracted a drilling rig for a 10 gross well development
drilling program to commence in the latter half of 2014.  
Exploration activities continue to progress in both Cote d'Ivoire and
South Africa. In Cote d'Ivoire, the operator in Block CI-514
commenced drilling 1 exploratory well in March 2014. Subsequently,
the operator completed drilling and encountered the presence of light
oil. The well was plugged and the data gathered will now be evaluated
to determine the extent of the accumulation and the forward plan for
appraisal. In South Africa, the operator is targeting to commence
drilling 1 exploratory well in the third quarter of 2014.  
LIQUIDITY AND CAPITAL RESOURCES 


 
 
                                           ---------------------------------
                                               Mar 31     Dec 31     Mar 31 
($ millions, except ratios)                      2014       2013       2013 
----------------------------------------------------------------------------
Working capital deficit (1)                 $   1,025  $   1,574  $   1,178 
Long-term debt (2) (3)                      $  10,354  $   9,661  $   9,322 
 
Share capital                               $   4,100  $   3,854  $   3,742 
Retained earnings                              22,193     21,876     20,564 
Accumulated other comprehensive income             44         42         68 
----------------------------------------------------------------------------
Shareholders' equity                        $  26,337  $  25,772  $  24,374 
 
Debt to book capitalization (3) (4)                28%        27%        28%
Debt to market capitalization (3) (5)              18%        20%        21%
After-tax return on average common                                          
 shareholders' equity (6)                          11%         9%         7%
After-tax return on average capital                                         
 employed (3) (7)                                   8%         7%         6%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Calculated as current assets less current liabilities, excluding
the current portion of long-term debt.  
(2) Includes the current portion of long-term debt.  
(3) Long-term debt is stated at its carrying value, net of fair value
adjustments, original issue discounts and transaction costs.  
(4) Calculated as current and long-term debt; divided by the book
value of common shareholders' equity plus current and long-term debt. 
(5) Calculated as current and long-term debt; divided by the market
value of common shareholders' equity plus current and long-term debt. 
(6) Calculated as net earnings for the twelve month trailing period;
as a percentage of average common shareholders' equity for the
period.  
(7) Calculated as net earnings plus after-tax interest and other
financing expense for the twelve month trailing period; as a
percentage of average capital employed for the period.    
At March 31, 2014, 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 annual MD&A
for the year ended December 31, 2013. 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 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.  
As at March 31, 2014, the Company had in place bank credit facilities
of $5,803 million, of which $4,561 million, net of commercial paper
issuances of $553 million, was available. Credit facilities at March
31, 2014 included a $1,000 million non-revolving term credit facility
arranged in connection with the acquisition of certain producing
Canadian crude oil and natural gas properties announced in the first
quarter of 2014. On April 1, 2014, the Company completed the
acquisition of the crude oil and natural gas properties for
preliminary cash consideration of $3,092 million, before final
purchase adjustments.  
During the first quarter of 2014, the Company issued US$500 million
of three-month LIBOR plus 0.375% notes due March 2016, and
concurrently, entered into cross currency swaps to fix the foreign
currency exchange rate risk at three-month CDOR plus 0.309% and $555
million. In addition, the Company issued US$500 million of 3.80%
notes due April 2024. Proceeds from the securities were used to repay
bank indebtedness. At March 31, 2014, the Company had maturities of
long-term debt aggregating $945 million over the next 12 months
(US$500 million due November 2014, US$350 million due December 2014). 
Long-term debt was $10,354 million at March 31, 2014, resulting in a
debt to book capitalization ratio of 28% (December 31, 2013 - 27%;
March 31, 2013 - 28%). 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 operations 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 production
for 2014 and 2015 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 March 31, 2014 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 May 7, 2014, an average of approximately
297,000 bbl/d of currently forecasted 2014 crude oil volumes and
50,000 bbl/d of currently forecasted 2015 crude oil volumes were
hedged using price collars and physical crude oil sales contracts
with fixed WCS differentials. An additional 500,000 MMBtu/d of
natural gas volumes were hedged for April 2014 to October 2014 using
AECO basis swaps and 200,000 GJ/d of natural gas volumes were hedged
for April 2014 to December 2014 using price collars. Further details
related to the Company's commodity derivative financial instruments
outstanding at March 31, 2014 are discussed in note 13 to the
Company's unaudited interim consolidated financial statements.  
Share Capital  
As at March 31, 2014, there were 1,092,120,000 common shares
outstanding (March 31, 2013 - 1,092,264,000 common shares) and
68,304,000 stock options outstanding. As at May 7, 2014, the Company
had 1,093,271,000 common shares outstanding and 66,377,000 stock
options outstanding.  
On March 5, 2014, the Company's Board of Directors approved an
increase in the annual dividend to $0.90 per common share (previous
annual dividend rate of $0.80 per common share), beginning with the
quarterly dividend payable on April 1, 2014 at $0.225 per common
share. This represents a 13% increase from the previous quarterly
dividend, reflecting 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 2014, 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 2014 and ending April 2015, up to 54,596,899
common shares. The Company's Normal Course Issuer Bid announced in
2013 expired April 2014.  
For the three months ended March 31, 2014, the Company purchased for
cancellation 1,775,000 common shares at a weighted average price of
$36.83 per common share, for a total cost of $65 million. Retained
earnings were reduced by $59 million, representing the excess of the
purchase price of common shares over their average carrying value.
Subsequent to March 31, 2014, the Company purchased 330,000 common
shares at a weighted average price of $43.44 per common share for a
total cost of $14 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 March 31, 2014: 


 
 
                           Remaining                                        
($ millions)                    2014   2015   2016   2017   2018  Thereafter
----------------------------------------------------------------------------
Product transportation                                                      
 and pipeline             $      238 $  307 $  238 $  212 $  176 $     1,324
Offshore equipment                                                          
 operating leases and                                                       
 offshore drilling        $      119 $  247 $   84 $   63 $   57 $        18
Long-term debt (1)        $    1,493 $  400 $1,221 $1,386 $  442 $     5,476
Interest and other                                                          
 financing expense (2)    $      367 $  432 $  408 $  349 $  300 $     4,032
Office leases             $       29 $   44 $   45 $   48 $   50 $       343
Other                     $      239 $  173 $   72 $    1 $    1 $         1
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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 expense 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 March 31, 2014.  
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 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 three months ended
March 31, 2014. 
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, 2013. 
CONSOLIDATED BALANCE SHEETS 


 
 
                                                      ----------------------
As at                                                      Mar 31     Dec 31
(millions of Canadian dollars, unaudited)         Note       2014       2013
----------------------------------------------------------------------------
ASSETS                                                                      
Current assets                                                              
  Cash and cash equivalents                            $       19 $       16
  Accounts receivable                                       1,918      1,427
  Inventory                                                   748        632
  Prepaids and other                                          174        141
----------------------------------------------------------------------------
                                                            2,859      2,216
Exploration and evaluation assets                  3        2,680      2,609
Property, plant and equipment                      4       47,299     46,487
Other long-term assets                             5          410        442
----------------------------------------------------------------------------
                                                       $   53,248 $   51,754
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
LIABILITIES                                                                 
Current liabilities                                                         
  Accounts payable                                     $      822 $      637
  Accrued liabilities                                       2,653      2,519
  Current income taxes                                         22        359
  Current portion of long-term debt                6        1,498      1,444
  Current portion of other long-term liabilities   7          387        275
----------------------------------------------------------------------------
                                                            5,382      5,234
Long-term debt                                     6        8,856      8,217
Other long-term liabilities                        7        4,307      4,348
Deferred income taxes                                       8,366      8,183
----------------------------------------------------------------------------
                                                           26,911     25,982
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY                                                        
Share capital                                      9        4,100      3,854
Retained earnings                                          22,193     21,876
Accumulated other comprehensive income             10          44         42
----------------------------------------------------------------------------
                                                           26,337     25,772
----------------------------------------------------------------------------
                                                       $   53,248 $   51,754
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments and contingencies (note 14).                                    
 
Approved by the Board of Directors on May 8, 2014                           
 
CONSOLIDATED STATEMENTS OF EARNINGS                                         
                                                         Three Months Ended 
                                                      ----------------------
(millions of Canadian dollars, except per common           Mar 31     Mar 31
 share amounts, unaudited)                       Note        2014       2013
----------------------------------------------------------------------------
Product sales                                          $    4,968 $    4,101
Less: royalties                                             (572)      (346)
----------------------------------------------------------------------------
Revenue                                                     4,396      3,755
----------------------------------------------------------------------------
Expenses                                                                    
Production                                                  1,211      1,135
Transportation and blending                                   831        855
Depletion, depreciation and amortization           4        1,011      1,142
Administration                                                 90         79
Share-based compensation                           7          143         71
Asset retirement obligation accretion              7           45         42
Interest and other financing expense                           68         77
Risk management activities                        13         (26)       (21)
Foreign exchange loss                                         117         46
Equity loss from joint venture                     5            1          2
----------------------------------------------------------------------------
                                                            3,491      3,428
----------------------------------------------------------------------------
Earnings before taxes                                         905        327
Current income tax expense                         8          126        141
Deferred income tax expense (recovery)             8          157       (27)
----------------------------------------------------------------------------
Net earnings                                           $      622 $      213
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common share                                               
  Basic                                           12   $     0.57 $     0.19
  Diluted                                         12   $     0.57 $     0.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME                             
 
                                                         Three Months Ended 
                                                      ----------------------
                                                          Mar 31     Mar 31 
(millions of Canadian dollars, unaudited)                   2014       2013 
----------------------------------------------------------------------------
Net earnings                                           $     622  $     213 
----------------------------------------------------------------------------
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 $nil (2013 - $2 million)                               1         16 
    Reclassification to net earnings, net of taxes of                       
     $nil (2013 - $nil)                                        3         (1)
----------------------------------------------------------------------------
                                                               4         15 
  Foreign currency translation adjustment                                   
    Translation of net investment                             (2)        (5)
----------------------------------------------------------------------------
Other comprehensive income, net of taxes                       2         10 
----------------------------------------------------------------------------
Comprehensive income                                   $     624  $     223 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY                                
 
                                                        Three Months Ended  
                                                      ----------------------
                                                          Mar 31     Mar 31 
(millions of Canadian dollars, unaudited)        Note       2014       2013 
----------------------------------------------------------------------------
Share capital                                      9                        
Balance - beginning of period                          $   3,854  $   3,709 
Issued upon exercise of stock options                        195         30 
Previously recognized liability on stock options                            
 exercised for common shares                                  57          7 
Purchase of common shares under Normal Course                               
 Issuer Bid                                                   (6)        (4)
----------------------------------------------------------------------------
Balance 
- end of period                                    4,100      3,742 
----------------------------------------------------------------------------
Retained earnings                                                           
Balance - beginning of period                             21,876     20,516 
Net earnings                                                 622        213 
Purchase of common shares under Normal Course                               
 Issuer Bid                                        9         (59)       (28)
Dividends on common shares                         9        (246)      (137)
----------------------------------------------------------------------------
Balance - end of period                                   22,193     20,564 
----------------------------------------------------------------------------
Accumulated other comprehensive income            10                        
Balance - beginning of period                                 42         58 
Other comprehensive income, net of taxes                       2         10 
----------------------------------------------------------------------------
Balance - end of period                                       44         68 
----------------------------------------------------------------------------
Shareholders' equity                                   $  26,337  $  24,374 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
CONSOLIDATED STATEMENTS OF CASH FLOWS                                       
 
                                                         Three Months Ended 
                                                      ----------------------
                                                          Mar 31     Mar 31 
(millions of Canadian dollars, unaudited)                   2014       2013 
----------------------------------------------------------------------------
Operating activities                                                        
Net earnings                                           $     622  $     213 
Non-cash items                                                              
  Depletion, depreciation and amortization                 1,011      1,142 
  Share-based compensation                                   143         71 
  Asset retirement obligation accretion                       45         42 
  Unrealized risk management loss                             49         62 
  Unrealized foreign exchange loss                           118         78 
  Realized foreign exchange gain on repayment of US                         
   dollar debt securities                                      -        (12)
  Equity loss from joint venture                               1          2 
  Deferred income tax expense (recovery)                     157        (27)
Other                                                         31         38 
Abandonment expenditures                                     (87)       (55)
Net change in non-cash working capital                      (737)      (389)
----------------------------------------------------------------------------
                                                           1,353      1,165 
----------------------------------------------------------------------------
Financing activities                                                        
(Repayment) issue of bank credit facilities and                             
 commercial paper, net                                      (661)     1,256 
Repayment of medium-term notes                                 -       (400)
Issue (repayment) of US dollar debt securities, net        1,100       (398)
Issue of common shares on exercise of stock options          195         30 
Purchase of common shares under Normal Course Issuer                        
 Bid                                                         (65)       (32)
Dividends on common shares                                  (217)      (115)
Net change in non-cash working capital                        (5)        (6)
----------------------------------------------------------------------------
                                                             347        335 
----------------------------------------------------------------------------
Investing activities                                                        
Net expenditures on exploration and evaluation assets       (117)       (77)
Net expenditures on property, plant and equipment         (1,689)    (1,604)
Net change in non-cash working capital                       109        162 
----------------------------------------------------------------------------
                                                          (1,697)    (1,519)
----------------------------------------------------------------------------
Increase (decrease) in cash and cash equivalents               3        (19)
Cash and cash equivalents - beginning of period               16         37 
----------------------------------------------------------------------------
Cash and cash equivalents - end of period              $      19  $      18 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid                                          $     135  $     142 
Income taxes paid                                      $     455  $     213 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 
(tabular amounts in millions of Canadian dollars, unless otherwise
stated, unaudited) 
1. ACCOUNTING POLICIES  
Canadian Natural Resources Limited (the "Company") is a senior
independent crude oil and natural gas exploration, development and
production company. The Company's exploration and production
operations are focused in North America, largely in Western Canada;
the United Kingdom ("UK") portion of the North Sea; and Cote
d'Ivoire, Gabon, and South Africa in Offshore Africa.  
The Horizon Oil Sands Mining and Upgrading segment ("Horizon")
produces synthetic crude oil through bitumen mining and upgrading
operations.  
Within Western Canada, the Company maintains certain midstream
activities that include pipeline operations, an electricity
co-generation system and an investment in the North West Redwater
Partnership ("Redwater Partnership"), a general partnership formed in
the Province of Alberta.  
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, 2013, 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, 2013. 
2. CHANGES IN ACCOUNTING POLICIES  
Effective January 1, 2014, the Company adopted IFRS 9 "Financial
Instruments". IFRS 9 replaces the sections of IAS 39 "Financial
Instruments: Recognition and Measurement" that relate to the
classification and measurement of financial instruments and hedge
accounting.  
IFRS 9 replaces the multiple classification and measurement models
for financial assets with a new model that has only two measurement
categories: amortized cost and fair value through profit or loss.
This determination is made at initial recognition. For financial
liabilities, the new standard retains most of the IAS 39
requirements. The main change arises in cases where the Company
chooses to designate a financial liability as fair value through
profit or loss. In these situations, the portion of the fair value
change related to the Company's own credit risk is recognized in
other comprehensive income rather than net earnings. As a result of
adopting IFRS 9, all of the Company's financial assets as at December
31, 2013 have been reclassified from loans and receivables at
amortized cost to financial assets at amortized cost. There were no
changes to the classifications of the Company's financial
liabilities. In addition, there were no changes in the carrying
values of the Company's financial instruments as a result of the
adoption of IFRS 9. The classification and measurement guidance was
adopted retrospectively in accordance with the transition provisions
of IFRS 9.  
The Company also adopted the new hedge accounting guidance in IFRS 9.
The new hedge accounting guidance replaces strict quantitative tests
of effectiveness with less restrictive assessments of how well the
hedging instrument accomplishes the Company's risk management
objectives for financial and non-financial risk exposures. IFRS 9
also allows the Company to hedge risk components of non-financial
items which meet certain measurability or identifiable
characteristics.  
Upon adoption of IFRS 9, all of the Company's existing hedging
relationships that qualified for hedge accounting under IAS 39 were
reassessed with respect to the new hedge accounting requirements in
IFRS 9. The hedging relationships have been continued under IFRS 9.
The hedge accounting requirements in IFRS 9 have been applied
prospectively in accordance with the transition provisions of IFRS 9. 
After adoption of IFRS 9, the Company's accounting policies are
substantially the same as at December 31, 2013, except for the change
in financial asset categories as discussed above.  
3. EXPLORATION AND EVALUATION ASSETS  


 
 
                                                         Oil Sands          
                                                         Mining and         
                           Exploration and Production     Upgrading   Total 
----------------------------------------------------------------------------
                            North      North   Offshore                     
                          America        Sea     Africa                     
----------------------------------------------------------------------------
Cost                                                                        
At December 31, 2013    $   2,570  $       - $       39 $         - $ 2,609 
Additions                     100          -         17           -     117 
Transfers to property,                                                      
 plant and equipment          (47)         -          -           -     (47)
Foreign exchange                                                            
 adjustments                    -          -          1           -       1 
----------------------------------------------------------------------------
At March 31, 2014       $   2,623  $       - $       57 $         - $ 2,680 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
4. PROPERTY, PLANT AND EQUIPMENT                                            
 
                                          Exploration and Production        
----------------------------------------------------------------------------
                                                                    Offshore
                              North America        North Sea          Africa
----------------------------------------------------------------------------
Cost                                                                        
At December 31, 2013        $        53,810  $         5,200 $         3,356
Additions                               998               88               -
Transfers from E&E assets                47                -               -
Disposals/derecognitions                (76)               -               -
Foreign exchange                                                            
 adjustments and other                    -              205             131
----------------------------------------------------------------------------
At March 31, 2014           $        54,779  $         5,493 $         3,487
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and                                                   
 depreciation                                                               
At December 31, 2013        $        28,315  $         3,467 $         2,551
Expense                                 811               57               5
Disposals/derecognitions                (76)               -               -
Foreign exchange                                                            
 adjustments and other                    5              135             118
----------------------------------------------------------------------------
At March 31, 2014           $        29,055  $         3,659 $         2,674
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value                                                              
- at March 31, 2014         $        25,724  $         1,834 $           813
- at December 31, 2013      $        25,495  $         1,733 $           805
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                             Oil Sands                                      
                            Mining and                    Head              
                             Upgrading   Midstream      Office        Total 
----------------------------------------------------------------------------
 
----------------------------------------------------------------------------
Cost                                                                        
At December 31, 2013      $     19,366 $       508 $       308  $    82,548 
Additions                          579          25          10        1,700 
Transfers from E&E assets            -           -           -           47 
Disposals/derecognitions           (7)           -          (1)         (84)
Foreign exchange                                                            
 adjustments and other               -           -           -          336 
----------------------------------------------------------------------------
At March 31, 2014         $     19,938 $       533 $       317  $    84,547 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and                                                   
 depreciation                                                               
At December 31, 2013      $      1,414 $       111 $       203  $    36,061 
Expense                            130           2           6        1,011 
Disposals/derecognitions           (7)           -          (1)         (84)
Foreign exchange                                                            
 adjustments and other               2           -           -          260 
----------------------------------------------------------------------------
At March 31, 2014         $      1,539 $       113 $       208  $    37,248 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value                                                              
- at March 31, 2014       $     18,399 $       420 $       109  $    47,299 
- at December 31, 2013    $     17,952 $       397 $       105  $    46,487 
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Project costs not subject to depletion and                 Mar 31     Dec 31
 depreciation                                                2014       2013
----------------------------------------------------------------------------
Horizon                                                $    4,568 $    4,051
Kirby Thermal Oil Sands                                $      389 $    1,532
----------------------------------------------------------------------------
----------------------------------------------------------------------------

During the first quarter of 2014, the Company entered into an agreement
to acquire certain producing Canadian crude oil and natural gas
properties, together with undeveloped land. In connection with the
agreement, the Company arranged an additional $1,000 million
unsecured non-revolving bank credit facility maturing March 2016 and
with terms similar to the Company's current syndicated credit
facilities, available upon closing. Subsequently, the Company
completed the acquisition of these properties on April 1, 2014, for
preliminary cash consideration of approximately $3,092 million,
subject to final closing adjustments.  
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 the asset
is substantially available for its intended use. For the period ended
March 31, 2014, pre-tax interest of $47 million (March 31, 2013 - $36
million) was capitalized to property, plant and equipment using a
capitalization rate of 4.3% (March 31, 2013 - 4.5%). 
5. OTHER LONG-TERM ASSETS 


 
 
                                                      ----------------------
                                                           Mar 31     Dec 31
                                                             2014       2013
----------------------------------------------------------------------------
Investment in North West Redwater Partnership          $      305 $      306
Other                                                         105        136
----------------------------------------------------------------------------
                                                       $      410 $      442
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Other long-term assets include an investment in the 50% owned Redwater
Partnership. Based on Redwater Partnership's voting and
decision-making structure and legal form, the investment is accounted
for as a joint venture using the equity method. Redwater Partnership
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
("APMC"), 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 Partnership and its partners.  
As at March 31, 2014, Redwater Partnership had interim borrowings of
$955 million under credit facilities totaling $1,200 million maturing
on November 28, 2014. These facilities are secured by a floating
charge on the assets of Redwater Partnership with a mandatory
repayment required from future financing proceeds. At maturity or at
such later date as mutually agreed to by the lenders and Redwater
Partnership, the Company will be obligated to repay its 25% pro rata
share of any amount outstanding under the facility. As at May 7,
2014, interim borrowings under the facilities were $883 million.  
In April 2014, Redwater Partnership, the Company and APMC amended
certain terms of the processing agreements. In conjunction with these
amendments, the Company, along with APMC, each committed to provide
additional funding up to $350 million to attain Project completion
based on the revised Project cost estimate of approximately $8,500
million. The additional funding is to be in the form of subordinated
debt bearing interest at prime plus 6%, which is anticipated to form
part of the equity toll. As at May 7, 2014, the Company and APMC had
each provided $113 million of funding of subordinated debt. Should
final Project costs exceed the revised cost estimate, the Company and
APMC have agreed, subject to the Company being able to meet certain
funding conditions, to fund any shortfall in available third party
commercial lending required to attain Project completion.  
Redwater Partnership has entered into various agreements related to
the engineering, procurement and construction of the Project. These
contracts can be cancelled by Redwater Partnership upon notice
without penalty, subject to the costs incurred up to and in respect
of the cancellation.  
6. LONG-TERM DEBT 


 
 
                                                      ----------------------
                                                          Mar 31     Dec 31 
                                                            2014       2013 
----------------------------------------------------------------------------
Canadian dollar denominated debt, unsecured                                 
Bank credit facilities                                 $     562  $   1,246 
Medium-term notes                                          1,400      1,400 
----------------------------------------------------------------------------
                                                           1,962      2,646 
----------------------------------------------------------------------------
US dollar denominated debt, unsecured                                       
Commercial paper (March 31, 2014 - US$500 million;                          
 December 31, 2013 - US$500 million)                         553        532 
US dollar debt securities 
 (March 31, 2014 - US$7,150 million;              
 December 31, 2013 - US$6,150 million)                     7,903      6,541 
Less: original issue discount on US dollar debt                             
 securities (1)                                              (18)       (18)
----------------------------------------------------------------------------
                                                           8,438      7,055 
Fair value impact of interest rate swaps on US dollar                       
 debt securities (2)                                           6          9 
----------------------------------------------------------------------------
                                                           8,444      7,064 
----------------------------------------------------------------------------
Long-term debt before transaction costs                   10,406      9,710 
Less: transaction costs (1) (3)                              (52)       (49)
----------------------------------------------------------------------------
                                                          10,354      9,661 
Less: current portion of commercial paper                    553        532 
 current portion of other long-term debt (1) (2) (3)         945        912 
----------------------------------------------------------------------------
                                                       $   8,856  $   8,217 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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% notes due December
2014 was adjusted by $6 million (December 31, 2013 - $9 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 March 31, 2014, the Company had in place bank credit facilities
of $5,803 million, comprised of: 
- a $200 million demand credit facility;  
- a $75 million demand credit facility;  
- a $1,000 million non-revolving term credit facility maturing March
2016;  
- a $1,500 million revolving syndicated credit facility maturing June
2016;  
- a $3,000 million revolving syndicated credit facility maturing June
2017; and  
- a GBP 15 million demand credit facility related to the Company's
North Sea operations.  
Each of the $1,500 million and $3,000 million facilities is
extendible annually for one-year periods at the mutual agreement of
the Company and the lenders. If the facilities are not extended, the
full amount of the outstanding principal would be repayable on the
maturity date. Borrowings under these facilities may be made by way
of pricing referenced to Canadian dollar or US dollar bankers'
acceptances, or LIBOR, US base rate or Canadian prime loans.  
The Company's borrowings under the US commercial paper program are
authorized up to a maximum US$1,500 million. The Company reserves
capacity under its bank credit facilities for amounts outstanding
under this program.  
As described in note 4, in connection with the agreement to acquire
certain producing Canadian crude oil and natural gas properties, the
Company arranged an additional $1,000 million unsecured non-revolving
bank credit facility maturing March 2016 and with terms similar to
the Company's current syndicated credit facilities, available upon
closing. As at May 7, 2014, the Company had $1,000 million
outstanding under this facility.  
The Company's weighted average interest rate on bank credit
facilities and commercial paper outstanding as at March 31, 2014 was
1.6% (March 31, 2013 - 2.2%), and on long-term debt outstanding for
the period ended March 31, 2014 was 4.3% (March 31, 2013 - 4.5%).  
In addition to the outstanding debt, letters of credit and financial
guarantees aggregating $439 million, including a $59 million
financial guarantee related to Horizon and $237 million of letters of
credit related to North Sea operations, were outstanding at March 31,
2014. Subsequent to March 31, 2014, the financial guarantee related
to Horizon was reduced to $56 million. 
Medium-Term Notes  
The Company filed a base shelf prospectus in November 2013 that
allows for the issue of up to $3,000 million of medium-term notes in
Canada, which expires in December 2015. If issued, these securities
will bear interest as determined at the date of issuance. 
US Dollar Debt Securities  
During the first quarter of 2014, the Company issued US$500 million
of three-month LIBOR plus 0.375% notes due March 2016, and
concurrently entered into cross currency swaps to fix the foreign
currency exchange rate risk at three-month CDOR plus 0.309% and $555
million (note 13). In addition, the Company issued US$500 million of
3.80% notes due April 2024. Proceeds from the securities were used to
repay bank indebtedness. After issuing these securities, the Company
has US$2,000 million remaining on its outstanding US$3,000 million
base shelf prospectus that allows for the issue of US dollar debt
securities in the United States, which expires in December 2015. If
issued, these securities will bear interest as determined at the date
of issuance.  
7. OTHER LONG-TERM LIABILITIES 


 
 
                                                      ----------------------
                                                           Mar 31     Dec 31
                                                             2014       2013
----------------------------------------------------------------------------
Asset retirement obligations                           $    4,183 $    4,162
Share-based compensation                                      368        260
Risk management (note 13)                                      83        136
Other                                                          60         65
----------------------------------------------------------------------------
                                                            4,694      4,623
Less: current portion                                         387        275
----------------------------------------------------------------------------
                                                       $    4,307 $    4,348
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 5.0%
(December 31, 2013 - 5.0%). A reconciliation of the discounted asset
retirement obligations was as follows:  


 
 
                                                      ----------------------
                                                          Mar 31     Dec 31 
                                                            2014       2013 
----------------------------------------------------------------------------
Balance - beginning of period                          $   4,162  $   4,266 
  Liabilities incurred                                        11         62 
  Liabilities acquired                                         -        131 
  Liabilities settled                                        (87)      (207)
  Asset retirement obligation accretion                       45        171 
  Revision of estimates                                        -        375 
  Change in discount rate                                      -       (723)
  Foreign exchange adjustments                                52         87 
----------------------------------------------------------------------------
Balance - end of period                                $   4,183  $   4,162 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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. 


 
 
                                                      ----------------------
                                                          Mar 31     Dec 31 
                                                            2014       2013 
----------------------------------------------------------------------------
Balance - beginning of period                          $     260  $     154 
  Share-based compensation expense                           143        135 
  Cash payment for stock options surrendered                  (4)        (4)
  Transferred to common shares                               (57)       (50)
  Capitalized to Oil Sands Mining and Upgrading               26         25 
----------------------------------------------------------------------------
Balance - end of period                                      368        260 
Less: current portion                                        284        216 
----------------------------------------------------------------------------
                                                       $      84  $      44 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
 
                                                         Three Months Ended 
                                                      ----------------------
                                                          Mar 31     Mar 31 
                                                            2014       2013 
----------------------------------------------------------------------------
Current corporate income tax - North America           $     192  $     122 
Current corporate income tax - North Sea                     (15)        (7)
Current corporate income tax - Offshore Africa                 4         35 
Current PRT (1) recovery - North Sea                         (61)       (13)
Other taxes                                                    6          4 
----------------------------------------------------------------------------
Current income tax expense                                   126        141 
----------------------------------------------------------------------------
Deferred corporate income tax expense (recovery)              91         (4)
Deferred PRT (1) expense (recovery) - North Sea               66        (23)
----------------------------------------------------------------------------
Deferred income tax expense (recovery)                       157        (27)
----------------------------------------------------------------------------
Income tax expense                                     $     283  $     114 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Petroleum Revenue Tax.  
9. SHARE CAPITAL  
Authorized  
Preferred shares issuable in a series.  
Unlimited number of common shares without par value. 


 
 
                                            --------------------------------
                                            Three Months Ended Mar 31, 2014 
                                              Number of shares              
Issued common shares                                (thousands)      Amount 
----------------------------------------------------------------------------
Balance - beginning of period                        1,087,322  $     3,854 
Issued upon exercise of stock options                    6,573          195 
Previously recognized liability on stock                                    
 options exercised for common shares                         -           57 
Purchase of common shares under Normal                                      
 Course Issuer Bid                                      (1,775)          (6)
----------------------------------------------------------------------------
Balance - end of period                              1,092,120  $     4,100 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 5, 2014, the Board of Directors approved the regular
quarterly dividend at $0.225 per common share, an increase from the
previous quarterly dividend of $0.20 per common share, which was
approved on November 5, 2013. 
Normal Course Issuer Bid  
In April 2014, 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 2014 and ending April 2015, up to 54,596,899 common shares. The
Company's Normal Course Issuer Bid announced in 2013 expired April
2014.  
For the three months ended March 31, 2014, the Company purchased for
cancellation 1,775,000 common shares at a weighted average price of
$36.83 per common share, for a total cost of $65 million. Retained
earnings were reduced by $59 million, representing the excess of the
purchase price of common shares over their average carrying value.
Subsequent to March 31, 2014, the Company purchased 330,000 common
shares at a weighted average price of $43.44 per common share for a
total cost of $14 million.  
Stock Options  
The following table summarizes information relating to stock options
outstanding at March 31, 2014: 


 
 
                                     ---------------------------------------
                                         Three Months Ended Mar 31, 2014    
                                                                    Weighted
                                                                     average
                                                Stock options       exercise
                                                   (thousands)         price
----------------------------------------------------------------------------
Outstanding - beginning of period                      72,741  $       34.36
Granted                                                 3,723  $       36.29
Surrendered for cash settlement                          (437) $       29.74
Exercised for common shares                            (6,573) $       29.64
Forfeited                                              (1,150) $       35.52
----------------------------------------------------------------------------
Outstanding - end of period                            68,304  $       34.93
----------------------------------------------------------------------------
Exercisable - end of period                            20,276  $       37.23
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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: 


 
 
                                                      ----------------------
                                                          Mar 31     Mar 31 
                                                            2014       2013 
----------------------------------------------------------------------------
Derivative financial instruments designated as cash                         
 flow hedges                                           $      85  $     101 
Foreign currency translation adjustment                      (41)       (33)
----------------------------------------------------------------------------
                                                       $      44  $      68 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 March 31, 2014, the
ratio was within the target range at 28%.  
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.  


 
 
                                                      ----------------------
                                                          Mar 31     Dec 31 
                                                            2014       2013 
----------------------------------------------------------------------------
Long-term debt (1)                                     $  10,354  $   9,661 
Total shareholders' equity                             $  26,337  $  25,772 
Debt to book capitalization                                   28%        27%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
 
                                                         Three Months Ended 
                                                      ----------------------
                                                           Mar 31     Mar 31
                                                             2014       2013
----------------------------------------------------------------------------
Weighted average common shares outstanding - basic                          
 (thousands of shares)                                  1,089,929  1,092,431
Effect of dilutive stock options (thousands of shares)      3,298      2,057
----------------------------------------------------------------------------
Weighted average common shares outstanding - diluted                        
 (thousands of shares)                                  1,093,227  1,094,488
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings                                           $      622 $      213
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common share - basic                  $     0.57 $     0.19
  - diluted                                            $     0.57 $     0.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
 
              --------------------------------------------------------------
                                        Mar 31, 2014                        
----------------------------------------------------------------------------
                                Fair                  Financial             
                 Financial     value                liabilities             
                 assets at   through   Derivatives           at             
Asset            amortized    profit      used for    amortized             
 (liability)          cost   or loss       hedging         cost       Total 
----------------------------------------------------------------------------
Accounts                                                                    
 receivable    $     1,918 $       -  $          - $          -  $    1,918 
Accounts                                                                    
 payable                 -         -             -         (822)       (822)
Accrued                                                                     
 liabilities             -         -             -       (2,653)     (2,653)
Other long-                                                                 
 term                                                                       
 liabilities             -       (88)            5          (51)       (134)
Long-term debt                                                              
 (1)                     -         -             -      (10,354)    (10,354)
----------------------------------------------------------------------------
               $     1,918 $     (88) $          5 $    (13,880) $  (12,045)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                       Dec 31, 2013                         
----------------------------------------------------------------------------
 
                               Fair                   Financial             
                Financial     value                 liabilities             
                assets at   through   Derivatives            at             
Asset          amortized     profit      used for    amortized              
 (liability)         cost   or loss       hedging          cost       Total 
----------------------------------------------------------------------------
Accounts                                                                    
 receivable   $     1,427 $       -  $          -  $          -  $    1,427 
Accounts                                                                    
 payable                -         -             -          (637)       (637)
Accrued                                                                     
 liabilities            -         -             -        (2,519)     (2,519)
Other long-                                                                 
 term                                                                       
 liabilities            -       (39)          (97)          (56)       (192)
Long-term                                                                   
 debt (1)               -         -             -        (9,661)     (9,661)
----------------------------------------------------------------------------
              $     1,427 $     (39) $        (97) $    (12,873) $  (11,582)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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 recurring other
long-term liabilities and fixed rate long-term debt were outlined
below: 


 
 
                                     ---------------------------------------
                                                   Mar 31, 2014             
----------------------------------------------------------------------------
                                         Carrying                           
                                           amount          Fair value       
----------------------------------------------------------------------------
Asset (liability)(1) (5)                               Level 1      Level 2 
----------------------------------------------------------------------------
Other long-term liabilities           $       (83) $         -  $       (83)
Fixed rate long-term debt (2) (3) (4)      (9,239)     (10,305)           - 
----------------------------------------------------------------------------
                                      $    (9,322) $   (10,305) $       (83)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                                   Dec 31, 2013             
----------------------------------------------------------------------------
                                         Carrying                           
                                           amount          Fair value       
----------------------------------------------------------------------------
Asset (liability) (1) (5)                              Level 1      Level 2 
----------------------------------------------------------------------------
Other long-term liabilities           $      (136) $         -  $      (136)
Fixed rate long-term debt (2) (3) (4)      (7,883)      (8,628)           - 
----------------------------------------------------------------------------
                                      $    (8,019) $    (8,628) $      (136)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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% notes due December
2014 was adjusted by $6 million (December 31, 2013 - $9 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.  
(5) There were no transfers between Level 1 and Level 2 financial
instruments.  
The following provides a summary of the carrying amounts of
derivative financial instruments held and a reconciliation to the
Company's consolidated balance sheets.  


 
 
                                                      ----------------------
                                                         Mar 31,    Dec 31, 
Asset (liability)                                           2014       2013 
----------------------------------------------------------------------------
Derivatives held for trading                                                
  Crude oil price collars                              $     (30) $     (33)
  Foreign currency forward contracts                         (10)        (3)
  Natural gas AECO basis swaps                               (34)        (1)
  Natural gas AECO put options, net of put premium                          
   financing obligations                                     (14)        (2)
  Natural gas price collars                                    -          - 
Cash flow hedges                                                            
  Foreign currency forward contracts                          (2)        (1)
  Cross currency swaps                                         7        (96)
----------------------------------------------------------------------------
                                                       $     (83) $    (136)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Included within:                                                            
  Current portion of other long-term liabilities       $     (82) $     (38)
  Other long-term liabilities                                 (1)       (98)
----------------------------------------------------------------------------
                                                       $     (83) $    (136)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

For the period ended March 31, 2014, the Company recognized a gain of
$nil (December 31, 2013 - gain of $4 million) related to
ineffectiveness arising from cash flow hedges.  
The estimated fair value of derivative financial instruments in Level
1 and Level 2 at each measurement date have been determined based on
appropriate internal valuation methodologies and/or third party
indications. Level 2 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 quoted market inputs including crude oil and
natural gas forward benchmark commodity prices and volatility,
Canadian and United States forward interest rate yield curves, and
Canadian and United States foreign exchange rates, discounted to
present value as appropriate. 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. 
Risk Management  
The Company uses derivative financial instruments to manage its
commodity price, interest rate and foreign currency exposures. These
financial instruments are entered into solely for hedging purposes
and are not used for speculative purposes.  
The changes in estimated fair values of derivative financial
instruments included in the risk management liability were recognized
in the financial statements as follows: 


 
 
                                              ------------------------------
                                                 Three Months               
                                                        Ended     Year Ended
Asset (liability)                                Mar 31, 2014   Dec 31, 2013
----------------------------------------------------------------------------
Balance - beginning of period                  $        (136) $        (257)
Cost of outstanding put options                            15              9
Net change in fair value of outstanding                                     
 derivative financial instruments recognized                                
 in:                                                                        
  Risk management activities                             (49)           (39)
  Foreign exchange                                         98            165
  Other comprehensive income                                4            (5)
----------------------------------------------------------------------------
                                                         (68)          (127)
Add: put premium financing obligations (1)               (15)            (9)
----------------------------------------------------------------------------
Balance - end of period                                  (83)          (136)
Less: current portion                                    (82)           (38)
----------------------------------------------------------------------------
                                               $          (1) $         (98)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) The Company has negotiated payment of put option premiums with
various counterparties at the time of actual settlement of the
respective options. These obligations are reflected in the risk
management liability.  
Net (gains) losses from risk management activities were as
follows: 


 
 
                                                         Three Months Ended 
                                                      ----------------------
                                                          Mar 31     Mar 31 
                                                            2014       2013 
----------------------------------------------------------------------------
Net realized risk management gain                      $     (75) $     (83)
Net unrealized risk management loss                           49         62 
----------------------------------------------------------------------------
                                                       $     (26) $     (21)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 March 31, 2014, the Company had the
following derivative financial instruments outstanding to manage its
commodity price risk:  
Sales contracts  


 
 
                   Remaining term        Volume      Weighted average  Index
                                                                price       
----------------------------------------------------------------------------
Crude oil                                                                   
Price                                                                       
 collars (1)  Apr 2014 - Jun 2014  50,000 bbl/d  US$80.00 - US$123.09  Brent
              Apr 2014 - Dec 2014  50,000 bbl/d  US$75.00 - US$121.57  Brent
              Apr 2014 - Dec 2014  50,000 bbl/d  US$80.00 - US$120.17  Brent
              Apr 2014 - Dec 2014  50,000 bbl/d  US$90.00 - US$120.10  Brent
              Jul 2014 - Sep 2014  50,000 bbl/d  US$80.00 - US$122.09  Brent
              Jan 2015 - Dec 2015   8,000 bbl/d  US$80.00 - US$122.53  Brent
              Apr 2014 - Jun 2014  50,000 bbl/d  US$80.00 - US$107.84    WTI
              Apr 2014 - Dec 2014  50,000 bbl/d  US$75.00 - US$105.54    WTI
              Jul 2014 - Dec 2014  50,000 bbl/d  US$80.00 - US$107.81    WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Subsequent to March 31, 2014, the Company entered into an
additional 42,000 bbl/d of US$80.00 - US$120.33 Brent collars for the
period January to December 2015.  


 
 
                                                        Weighted            
                    Remaining term          Volume average price       Index
----------------------------------------------------------------------------
Natural gas                                                                 
AECO basis                                                                  
 swaps         Apr 2014 - Oct 2014 500,000 MMBtu/d       US$0.50  AECO/NYMEX
Put options    Apr 2014 - Oct 2014    750,000 GJ/d         $3.10        AECO
Price collars  Apr 2014 - Dec 2014    200,000 GJ/d $4.00 - $5.03        AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------

The cost of outstanding put options and their respective periods of
settlement as at March 31, 2014 were as follows: 


 
 
                                                 Q2 2014   Q3 2014   Q4 2014
----------------------------------------------------------------------------
Cost                                                  $6        $7        $2
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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. 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 March 31, 2014, 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 and in the carrying value of its foreign
subsidiaries. The Company periodically enters into cross currency
swap contracts and foreign currency forward contracts to manage known
currency exposure on US dollar denominated long-term debt, 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 March
31, 2014, 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       Apr 2014 - Mar 2016    US$500      1.109 Three-month Three-month
                                                      LIBOR plus    CDOR (1)
    0.375% plus 0.309%
            Apr 2014 - Aug 2016    US$250      1.116       6.00%       5.40%
            Apr 2014 - May 2017  US$1,100      1.170       5.70%       5.10%
            Apr 2014 - Nov 2021    US$500      1.022       3.45%       3.96%
            Apr 2014 - Mar 2038    US$550      1.170       6.25%       5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(1) Canadian Dealer Offered Rate ("CDOR").  
All cross currency swap derivative financial instruments designated
as hedges at March 31, 2014, were classified as cash flow hedges.  
In addition to the cross currency swap contracts noted above, at
March 31, 2014, the Company had US$2,193 million of foreign currency
forward contracts outstanding, with terms of approximately 30 days or
less, including US$500 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 March
31, 2014, 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 March 31, 2014,
the Company had net risk management assets of $3 million with
specific counterparties related to derivative financial instruments
(December 31, 2013 - $nil). 
c) Liquidity risk  
Liquidity risk is the risk that the Company will encounter difficulty
in meeting obligations associated with financial liabilities.  
Management of liquidity risk requires the Company to maintain
sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating activities,
available credit facilities, 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 were as follows: 


 
 
                                         1 to less    2 to less             
                            Less than         than         than             
                               1 year      2 years      5 years   Thereafter
----------------------------------------------------------------------------
Accounts payable         $        822 $          - $          - $          -
Accrued liabilities      $      2,653 $          - $          - $          -
Risk management          $         82 $          9 $          6 $       (14)
Other long-term                                                             
 liabilities             $         21 $         30 $          - $          -
Long-term debt (1)       $      1,493 $        952 $      2,497 $      5,476
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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                                        
                                2014   2015   2016   2017   2018  Thereafter
----------------------------------------------------------------------------
Product transportation                                                      
 and pipeline            $       238 $  307 $  238 $  212 $  176 $     1,324
Offshore equipment                                                          
 operating leases and                                                       
 offshore drilling       $       119 $  247 $   84 $   63 $   57 $        18
Office leases            $        29 $   44 $   45 $   48 $   50 $       343
Other                    $       239 $  173 $   72 $    1 $    1 $         1
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 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                         
                                                                  Total     
                                                               Exploration  
                                                   Offshore        and      
                    North America   North Sea       Africa      Production  
(millions of         Three Months  Three Months  Three Months  Three Months 
 Canadian               Ended         Ended         Ended         Ended     
 dollars,unaudited)     Mar 31        Mar 31        Mar 31        Mar 31    
                    --------------------------------------------------------
                      2014   2013   2014   2013   2014   2013   2014   2013 
----------------------------------------------------------------------------
Segmented product                                                           
 sales               3,657  2,808    198    177     24    208  3,879  3,193 
Less: royalties       (516)  (276)    (1)    (1)    (4)   (33)  (521)  (310)
----------------------------------------------------------------------------
Segmented revenue    3,141  2,532    197    176     20    175  3,358  2,883 
----------------------------------------------------------------------------
Segmented expenses                                                          
Production             663    605    123    102      7     47    793    754 
Transportation and                                                          
 blending              828    855      2      2      -      -    830    857 
Depletion,                                                                  
 depreciation and                                                           
 amortization          816    871     58    112      5     40    879  1,023 
Asset retirement                                                            
 obligation                                                                 
 accretion              22     23      9      9      2      2     33     34 
Realized risk                          -      -      -      -               
 management                                                                 
 activities            (75)   (83)                               (75)   (83)
Equity loss from                                                            
 joint venture           -      -      -      -      -      -      -      - 
----------------------------------------------------------------------------
Total segmented                                                             
 expenses            2,254  2,271    192    225     14     89  2,460  2,585 
----------------------------------------------------------------------------
Segmented earnings                                                          
 (loss) before the                                                          
 following             887    261      5    (49)     6     86    898    298 
----------------------------------------------------------------------------
Non-segmented                                                               
 expenses                                                                   
Administration                                                              
Share-based                                                                 
 compensation                                                               
Interest and other                                                          
 financing expense                                                          
Unrealized risk                                                             
 management                                                                 
 activities                                                                 
Foreign exchange                                                            
 loss                                                                       
----------------------------------------------------------------------------
Total non-segmented                                                         
 expenses                                                                   
----------------------------------------------------------------------------
Earnings before                                                             
 taxes                                                                      
Current income tax                                                          
 expense                                                                    
Deferred income tax                                                         
 expense (recovery)                                                         
----------------------------------------------------------------------------
Net earnings                                                                
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                        Oil Sands               Inter-segment               
                        Mining and               elimination                
                        Upgrading     Midstream   and other       Total     
(millions of Canadian  Three Months Three Months Three Months  Three Months 
 dollars,unaudited)       Ended         Ended       Ended         Ended     
                          Mar 31       Mar 31       Mar 31        Mar 31    
                      ------------------------------------------------------
                        2014   2013   2014  2013  2014   2013   2014   2013 
----------------------------------------------------------------------------
Segmented product                                                           
 sales                 1,082    909     31    27   (24)   (28) 4,968  4,101 
Less: royalties          (51)   (36)     -     -     -      -   (572)  (346)
----------------------------------------------------------------------------
Segmented revenue      1,031    873     31    27   (24)   (28) 4,396  3,755 
----------------------------------------------------------------------------
Segmented expenses                                                          
Production               412    377      9     8    (3)    (4) 1,211  1,135 
Transportation and                                                          
 blending                 20     15      -     -   (19)   (17)   831    855 
Depletion,                                                                  
 depreciation and                                                           
 amortization            130    117      2     2     -      -  1,011  1,142 
Asset retirement                         -     -     -      -               
 obligation accretion     12      8                               45     42 
Realized risk              -      -      -     -     -      -               
 management activities                                           (75)   (83)
Equity loss from joint                                                      
 venture                   -      -      1     2     -      -      1      2 
----------------------------------------------------------------------------
Total segmented                                                             
 expenses                574    517     12    12   (22)   (21) 3,024  3,093 
----------------------------------------------------------------------------
Segmented earnings                                                          
 (loss) before the                                                          
 following               457    356     19    15    (2)    (7) 1,372    662 
----------------------------------------------------------------------------
Non-segmented expenses                                                      
Administration                                                    90     79 
Share-based                                                                 
 compensation                                                    143     71 
Interest and other                                                          
 financing expense                                                68     77 
Unrealized risk                                                             
 management activities                                            49     62 
Foreign exchange loss                                            117     46 
----------------------------------------------------------------------------
Total non-segmented                                                         
 expenses                                                        467    335 
----------------------------------------------------------------------------
Earnings before taxes                                            905    327 
Current income tax                                                          
 expense                                                         126    141 
Deferred income tax                                                         
 expense (recovery)                                              157    (27)
----------------------------------------------------------------------------
Net earnings                                                     622    213 
----------------------------------------------------------------------------
----------------------------------------------------------------------------

Capital Expenditures (1) 


 
 
                                              Three Months Ended            
                               ---------------------------------------------
                                                 Mar 31, 2014               
----------------------------------------------------------------------------
                                                     Non-cash               
                                                     and fair               
                                           Net          value    Capitalized
                                  expenditures     changes(2)          costs
----------------------------------------------------------------------------
 
Exploration and evaluation                                                  
 assets                                                                     
Exploration and Production                                                  
 North America                  $          100 $         (47) $           53
 North Sea                                   -              -              -
 Offshore Africa                            17              -             17
----------------------------------------------------------------------------
                                $          117 $         (47) $           70
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Property, plant and equipment                                               
Exploration and Production                                                  
 North America                  $          987 $         (18) $          969
 North Sea                                  88              -             88
 Offshore Africa                             -              -              -
----------------------------------------------------------------------------
                                         1,075           (18)          1,057
Oil Sands Mining and Upgrading                                              
 (3)                                       579            (7)            572
Midstream                                   25              -             25
Head office                                 10            (1)              9
----------------------------------------------------------------------------
                                $        1,689 $         (26) $        1,663
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                             Three Months Ended             
                               ---------------------------------------------
                                                 Mar 31, 2013               
----------------------------------------------------------------------------
                                                    Non-cash                
                                                     and fair               
                                           Net          value    Capitalized
                                  expenditures     changes(2)          costs
----------------------------------------------------------------------------
 
Exploration and evaluation                                                  
 assets                                                                     
Exploration and Production                                                  
 North America                  $           76 $         (22) $           54
 North Sea                                   -              -              -
 Offshore Africa                             1              -              1
----------------------------------------------------------------------------
                                $           77 $         (22) $           55
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Property, plant and equipment                                               
Exploration and Production                                                  
 North America                  $        1,017 $         (34) $          983
 North Sea                                  85              -             85
 Offshore Africa                            29              -             29
----------------------------------------------------------------------------
                                         1,131           (34)          1,097
Oil Sands Mining and Upgrading                                              
 (3)                                       461          (116)            345
Midstream                                    5              -              5
Head office                                  7              -              7
----------------------------------------------------------------------------
                                $        1,604 $        (150) $        1,454
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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    
                                                      ----------------------
                                                           Mar 31     Dec 31
                                                             2014       2013
----------------------------------------------------------------------------
Exploration and Production                                                  
  North America                                        $   29,918 $   29,234
  North Sea                                                 2,059      1,964
  Offshore Africa                                           1,009        981
  Other                                                        50         25
Oil Sands Mining and Upgrading                             19,209     18,604
Midstream                                                     894        841
Head office                                                   109        105
----------------------------------------------------------------------------
                                                       $   53,248 $   51,754
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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 November 2013. 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 March           
 31, 2014:                                                                  
----------------------------------------------------------------------------
Interest coverage (times)                                                   
  Net earnings (1)                                                      8.8x
  Cash flow from operations (2)                                        20.0x
----------------------------------------------------------------------------
----------------------------------------------------------------------------

(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 Friday, May 9, 2014. The North American conference
call number is 1-877-223-4471 and the outside North American
conference call number is 001-647-788-4922. 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,
Friday, May 16, 2014. To access the rebroadcast in North America,
dial 1-800-585-8367. Those outside of North America, dial
001-416-621-4642. The conference ID number to use is 58303226. 
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 
Corey B. Bieber
Chief Financial Officer & Senior Vice-President, Finance 
Douglas A. Proll
Executive Vice-President 
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
 
 
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