Canadian Natural Resources Limited Announces 2012 Fourth Quarter and Year End Results

Canadian Natural Resources Limited Announces 2012 Fourth Quarter and Year End 
Results 
CALGARY, ALBERTA -- (Marketwire) -- 03/07/13 -- Canadian Natural
Resources Limited (TSX:CNQ) (NYSE:CNQ) 
Commenting on fourth quarter and year end results, Canadian Natural's
Vice-Chairman, John Langille stated, "Canadian Natural generated in
2012 over $6.0 billion of annual cash flow from operations and
demonstrated capital discipline throughout the year.  The Company's
exhibited long term ability to maintain flexibility of capital
allocation and financial discipline over different commodity price
cycles has helped us weather challenging conditions and capitalize
when opportunities arise.  Prudent management of our balance sheet
resulted in year-end debt to book capitalization of 26% and year-end
debt to EBITDA of 1.2 times. 
As part of the Company's long term goal to return funds to its
shareholders, throughout 2012, the Company purchased for cancellation
under its Normal Course Issuer Bid over eleven million common shares
at an average price of $28.91. For 2013, the Board has approved a 19%
dividend increase to C$0.125 per quarter, C$0.50 per share
annualized.  This will be the thirteenth consecutive year that the
Company has announced an increased annual dividend distribution
representing a compound annual growth rate of 21% over the period. 
In addition, the Company's Board of Directors have directed
Management to continue with an active program, subject to market
conditions, to purchase for cancellation common shares under the
Company's Normal Course Issuer Bid at or above the levels of shares
purchased in financial year 2012. Our share purchase program and
dividend increases, along with the defined resource development of
our diverse asset base, and our debt management and opportunistic
acquisitions demonstrate our balanced approach to our long standing
effective strategy.  Canadian Natural is strong and stable, and well
positioned to deliver shareholder value in the near, mid and long
term." 
Steve Laut, President of Canadian Natural concluded, "During 2012,
the Company made very good progress in our transition to a longer
life, low decline asset base. We continued to balance development of
our large resource base by focusing on high return assets and our
ability t
o deliver timely results. In 2012 we made significant
progress towards continued execution on the creation of shareholder
value.  We achieved 9% overall production growth in 2012 from 2011. 
At Horizon, substantial improvements have been made in operating
discipline and our enhanced concentration on safe, steady and
reliable operations has led to greater plant reliability.  At Kirby,
construction progress has been solid and we are 81% complete and on
budget.  We had another solid year of adding new reserves.  Our
barrel of oil equivalent reserves on a Company Gross proved plus
probable basis increased by 5% to 7.9 billion barrels, replacing 246%
of our 2012 production. 
For 2013 and beyond, we will continue to focus on operating
efficiencies and discipline and will allocate capital to projects
that provide the greatest value and highest returns to our
shareholders. This will allow the Company over time to generate
strong and growing free cash flow." 
QUARTERLY AND ANNUAL HIGHLIGHTS 


 
                             Three Months Ended             Year Ended
                     -------------------------------------------------------
 
($ Millions, except
 per common share         Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
 amounts)                   2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Net earnings          $      352 $      360 $      832 $    1,892 $    2,643
  Per common share -
   basic              $     0.32 $     0.33 $     0.76 $     1.72 $     2.41
  - diluted           $     0.32 $     0.33 $     0.76 $     1.72 $     2.40
Adjusted net earnings
 from operations (1)  $      359 $      353 $      972 $    1,618 $    2,540
  Per common share -
   basic              $     0.33 $     0.33 $     0.89 $     1.48 $     2.32
  - diluted           $     0.33 $     0.32 $     0.88 $     1.47 $     2.30
Cash flow from
 operations (2)       $    1,548 $    1,431 $    2,158 $    6,013 $    6,547
  Per common share -
   basic              $     1.41 $     1.31 $     1.97 $     5.48 $     5.98
  - diluted           $     1.41 $     1.30 $     1.96 $     5.47 $     5.94
Capital expenditures,
 net of dispositions  $    1,767 $    1,621 $    1,909 $    6,308 $    6,414
 
Daily production,
 before royalties
  Natural gas
   (MMcf/d)                1,134      1,191      1,280      1,220      1,257
  Crude oil and NGLs
   (bbl/d)               469,964    469,168    444,286    451,378    389,053
  Equivalent
   production (BOE/d)
   (3)                   658,973    667,616    657,599    654,665    598,526
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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. 
Fourth Quarter 
- Total crude oil and NGLs production was 469,964 bbl/d for Q4/12.
Q4/12 crude oil production volumes increased 6% from Q4/11 as a
result of a strong thermal in situ production cycle and successful
primary heavy and light crude oil drilling programs. 
- Total natural gas production for Q4/12 was 1,134 MMcf/d. Q4/12
natural gas production volumes decreased 11% and 5%, as expected,
from Q4/11 and Q3/12 respectively. The decrease in production was
primarily due to expected production declines and shut in production
volumes as a result of the Company's strategic decision to allocate
capital to higher return crude oil projects. 
- Canadian Natural generated quarterly cash flow from operations of
$1.55 billion compared with $2.16 billion in Q4/11 and $1.43 billion
in Q3/12. The decrease in cash flow from Q4/11 was due to lower
average realized product prices, lower natural gas sales volumes, and
lower synthetic crude oil ("SCO") sales volumes. These factors were
partially offset by higher crude oil sales volumes in North America.
The increase in cash flow from Q3/12 was primarily related to higher
North America crude oil and NGLs sales volumes. 
- Adjusted net earnings from operations for Q4/12 was $359 million,
compared to adjusted net earnings of $972 million in Q4/11 and $353
million in Q3/12. Changes in adjusted net earnings reflect the
changes in cash flow from operations. 
Annual 
- Total overall p
roduction for the year averaged 654,665 BOE/d
representing an increase of 9% from 2011. Canadian Natural's
production volume growth was driven by successful light and heavy
crude oil drilling programs and greater reliability of Horizon Oil
Sands ("Horizon") operations. 
- Total crude oil and NGLs production for the year averaged 451,378
bbl/d, an increase of 16% from 2011. The Company's strategic
allocation of capital to crude oil projects resulted in a 22% annual
increase in primary heavy crude oil production volumes, a 13% annual
increase of North America light crude oil and NGLs production and a
113% annual increase in Horizon production. 
- As expected, total natural gas production for the year averaged
1,220 MMcf/d, a decrease of 3% from 2011 levels.  The decrease in
production was due to expected production declines, shut in
production volumes and a reduced drilling program, reflecting
Canadian Natural's strategic decision to allocate capital to higher
return crude oil projects. 
- Cash flow from operations was approximately $6.0 billion in 2012
compared to approximately $6.5 billion in 2011. The decrease in cash
flow was primarily due to lower realized crude oil and NGLs prices,
lower realized natural gas prices and lower realized SCO prices.
These factors were partially offset by higher crude oil and SCO
production volumes in North America. 
- Adjusted net earnings from operations in 2012 decreased to $1.6
billion compared to $2.5 billion in 2011. Changes in adjusted net
earnings reflect the changes in cash flow from operations and higher
depletion, depreciation and amortization ("DD&A") expense. 
- Canadian Natural's crude oil and natural gas reserves were reviewed
and evaluated by independent qualified reserves evaluators. The
following are highlights based on the Company Gross reserves using
forecast prices and costs as at December 31, 2012: 
-- Company Gross proved crude oil, SCO, bitumen and NGL reserves
increased 6% to 4.33 billion barrels. Company Gross proved natural
gas reserves decreased 7% to 4.14 Tcf. On a BOE basis total proved
reserves increased 4% to 5.02 billion BOE. 
-- Company Gross proved plus probable crude oil, SCO, bitumen and NGL
reserves increased 6% to 6.92 billion barrels. Company Gross proved
plus probable natural gas reserves decreased 5% to 5.79 Tcf. On a BOE
basis total proved plus probable reserves increased 5% to 7.89
billion BOE. 
-- Company Gross proved reserve additions, including acquisitions,
were 404 million barrels of crude oil, SCO, bitumen and NGL and 135
billion cubic feet of natural gas for 426 million BOE. The total
proved reserve replacement ratio was 178%. The total proved reserve
life index is 22.8 years. 
-- Company Gross proved plus probable reserve additions, including
acquisitions, were 565 million barrels of crude oil, bitumen, SCO and
NGL and 132 billion cubic feet of natural gas for 587 million BOE.
The total proved plus probable reserve replacement ratio was 246%.
The total proved plus probable reserve life index is 35.8 years. 
-- Proved undeveloped crude oil, SCO, bitumen and NGL reserves
accounted for 31% of the corporate total proved reserves and proved
undeveloped natural gas reserves accounted for 4% of the corporate
total proved reserves. 
-- Of the reserve additions by the Company in 2012, 95% of Company
Gross proved reserve additions and 96% of Company Gross proved plus
probable reserve additions were crude oil, SCO, bitumen and NGLs. 
- Total net exploration and production reserve replacement
expenditures totaled approximately $4,444 million in 2012, including
acquisitions and excluding Horizon. Horizon project capital
(including capitalized interest, share-based compensation and other)
totaled approximately $1,366 million and sustaining and turnaround
capital totaled approximately $244 million. 
Operational and Financial 
- North America Exploration and Production crude oil and NGLs
production for the year averaged 326,829 bbl/d representing an
increase of 11% from 2011 levels. 
-- Canadian Natural's primary heavy crude oil continued to provide
strong netbacks and the highest return on capital in the Company's
portfolio of diverse and balanced assets. Primary heavy crude oil
operations achieved Q4/12 production volumes of over 130,000 bbl/d,
resulting in the eighth consecutive quarter of record production
which contributed to 22% average annual production growth over 2011.
Primary heavy crude oil production volumes are targeted to increase
by a further 13% in 2013. 
-- Completion of another successful light crude oil drilling program
of 124 net wells, Enhanced Oil Recovery ("EOR") activities and
acquisitions resulted in 13% annual growth of North America light
crude oil and NGLs production volumes over 2011 levels. North America
light crude oil and NGLs production volumes in 2013 are targeted to
increase by 6%. 
-- Pelican Lake reservoir performance throughout 2012 was very
positive.  In Q4/12, production averaged approximately 36,400 bbl/d
as volumes at Pelican Lake were restricted due to temporary produced
polymer treatment and facility constraints.  In addition, production
volumes from the primary heavy oil area of Woodenhouse were also
restricted as they utilize Pelican Lake processing facilities.
Construction completion of a new battery targeted in June 2013 will
correct the temporary treatment constraints and enable a step
increase in Pelican Lake and Woodenhouse production volumes through
the second half of 2013.  Annual production guidance for Pelican Lake
remains unchanged and is targeted to range from 46,000 bbl/d to
50,000 bbl/d. 
-- Thermal in situ production ramped up during 2012 as pads
re-entered the production cycle. Q4/12 volumes averaged 121,000
bbl/d, a 19% increase over Q3/12 volumes. 2012 annual thermal
production averaged approximately 99,500 bbl/d and is targeted to
grow by 5% in 2013. 
-- In 2012, Canadian Natural acquired an additional 12,630 net
hectares of leases at its Kirby Thermal Oil Sands Project ("Kirby
Project"), which are being incorporated into the Company's robust
portfolio of thermal in situ projects.  The Company's thermal
projects are targeted to add 40,000 bbl/d of production every two to
three years that is targeted to ultimately grow to approximately
500,000 bbl/d of capacity, from current production capacity of
130,000 bbl/d. The Company Gross proved plus probable long-life,
low-decline bitumen reserves from thermal in situ oil sands increased
by 23%, to 2,122 million barrels in 2012 and total Company Gross
proved bitumen reserves increased by 9%, to 1,066 million barrels in
2012. 
-- Kirby South Phase 1, the Company's first large scale steam
assisted gravity drainage ("SAGD") project, is targeted for first
steam in Q4/13 and is targeted to add 40,000 bbl/d of production in
late 2014. Construction is progressing slightly ahead of schedule and
on budget. 
- Horizon SCO production volumes averaged approximately 86,000 bbl/d
in 2012. The Company continues its enhanced focus on operational
discipline and safe, steady and reliable operations at Horizon.
Reliability of the Horizon plant continues to steadily improve and
annual SCO production is targeted to range from 100,000 bbl/d to
108,000 bbl/d in 2013, which includes the impact of the planned May
2013 turnaround. 
-- The addition of the third ore preparation plant ("OPP") 
and
associated hydro-transport unit was integrated into the Company's
mining operations in early 2012. The equipment has substantially
increased the overall reliability at Horizon. 
-- In January and February 2013, strong performance from Horizon
resulted in average SCO volumes of approximately 113,000 bbl/d and
107,000 bbl/d, respectively.  Q1/13 production guidance is targeted
to range from 105,000 bbl/d to 111,000 bbl/d of SCO. 
-- Canadian Natural maintains a flexible schedule for Horizon
expansion construction to ensure capital efficiencies. The staged
expansion to 250,000 bbl/d of SCO production capacity at Horizon
continues to be broken down into smaller more focused projects which
has kept projects currently under construction trending at or below
cost estimates. In 2012, long life, low decline SCO Company Gross
proved reserves increased 6% to 2.26 billion barrels. SCO Company
Gross proved plus probable reserves remained essentially unchanged at
3.35 billion barrels. 
- During Q4/12, the Redwater Partnership 50,000 bbl/d bitumen
refinery (78,000 bbl/d of bitumen blend) was sanctioned by its owners
(50% Canadian Natural). The Company will provide 12,500 bbl/d of
bitumen feedstock to the refinery as a toll payer. Work continues on
the Redwater project and completion is targeted for mid-2016. 
- During 2012, Canadian Natural purchased 11,012,700 common shares
for cancellation at a weighted average price of $28.91 per common
share. 
- For 2013, the Board has approved a 19% dividend increase to C$0.125
per quarter, C$0.50 per share annualized.  This will be the
thirteenth consecutive year that the Company has announced an
increased annual dividend distribution representing a compound annual
growth rate of 21% over the period. 
- In addition, the Company's Board of Directors have directed
Management to continue with an active program, subject to market
conditions, to purchase for cancellation common shares under the
Company's Normal Course Issuer Bid at or above the levels of shares
purchased in financial year 2012. 
OPERATIONS REVIEW AND CAPITAL ALLOCATION 
In order to facilitate efficient operations, Canadian Natural focuses
its activities in core regions where it can own a substantial land
base and associated infrastructure. Land inventories are maintained
to enable continuous exploitation of play types and geological
trends, greatly reducing overall exploration risk. By owning and
operating associated infrastructure, the Company is able to maximize
utilization of its production facilities, thereby increasing control
over production costs. Further, the Company maintains large project
inventories and production diversification among each of the
commodities it produces; light and medium crude oil, primary heavy
crude oil, Pelican Lake heavy crude oil, bitumen and SCO (herein
collectively referred to as "crude oil"), natural gas and NGLs. A
large diversified project portfolio enables the effective allocation
of capital to higher return opportunities. 
OPERATIONS REVIEW 


 
 
 
Activity by core region
                            Net unproved properties
                                              as at        Drilling activity
                                       Dec 31, 2012               year ended
                                  (thousands of net             Dec 31, 2012
                                          acres)(1)           (net wells)(2)
----------------------------------------------------------------------------
North America
  Northeast British
   Columbia                                   2,954                     20.6
  Northwest Alberta                           2,196                     51.9
  Northern Plains                             6,603                    984.8
  Southern Plains                             1,026                     43.8
  Southeast Saskatchewan                        100                     37.0
  Thermal In Situ Oil
   Sands                                        837                    556.0
----------------------------------------------------------------------------
                                             13,716                  1,694.1
Oil Sands Mining and
 Upgrading                                       59                    303.0
North Sea                                       128                      0.9
Offshore Africa                               4,307                        -
----------------------------------------------------------------------------
                                             18,210                  1,998.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Unproved land refers to a property or part of a property to which
no reserves have been specifically attributed. 
(2) Drilling activity includes stratigraphic test and service wells. 


 
 
 
 
Drilling activity (number of wells)
                                                Year Ended Dec 31
                                      --------------------------------------
                                             2012               2011
                                          Gross      Net     Gross      Net
----------------------------------------------------------------------------
Crude oil                                 1,255    1,203       1,159  1,103
Natural gas                                  42       35       102       83
Dry                                          34       33        49       48
----------------------------------------------------------------------------
Subtotal                                  1,331    1,271     1,310    1,234
Stratigraphic test / service wells          728      727       659      657
----------------------------------------------------------------------------
Total                                     2,059    1,998     1,969    1,891
----------------------------------------------------------------------------
Success rate (excluding stratigraphic
 test / service wells)                                97%                96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
North America Exploration and Production 


 
North America crude oil and
 NGLs
                                 Three Months Ended          Year Ended
                           ------------------------------------------------
                              Dec 31    Sep 30    Dec 31   Dec 31    Dec 31
                                2012      2012      2011     2012      2011
----------------------------------------------------------------------------
Crude oil and NGLs
 production (bbl/d)          351,983   332,895   291,839  326,829   295,618
----------------------------------------------------------------------------
 
Net wells targeting crude
 oil                             313       371       345    1,236     1,147
Net s
uccessful wells
 drilled                         294       365       330    1,203     1,103
----------------------------------------------------------------------------
  Success rate                    94%       98%      96%       97%       96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- North America crude oil and NGLs production for the year averaged
326,829 bbl/d representing an increase of 11% from 2011. The increase
in average yearly production was largely a result of successful
drilling programs in primary heavy and light crude oil. 
- North America crude oil and NGLs production for Q4/12 was 351,983
bbl/d. Q4/12 crude oil and NGLs production volumes increased 21% and
6% from Q4/11 and Q3/12 levels, respectively. The increase in
production from Q4/11 was driven by higher primary heavy crude oil
and thermal production volumes. 
- Primary heavy crude oil operations achieved record quarterly
production in Q4/12 of approximately 130,200 bbl/d which contributed
to 22% average annual production growth over 2011 levels. Canadian
Natural executed a record drilling program of 886 net primary heavy
crude oil wells in 2012. 
- During 2012 the reservoir performance at Pelican Lake demonstrated
expected positive results. 
-- Strong operating efficiencies were achieved at Pelican Lake as
operating costs decreased to an annual average of $11.89/bbl in 2012. 
-- In Q4/12, reservoir performance remained strong with incremental
production response from the polymer flood. As production increased
to facility capacity, the ability to treat the polymer produced was
constrained. As a result, oil production at both Pelican Lake and
Woodenhouse was curtailed. 
-- Construction of the new battery, targeted for completion in June
2013, will address these temporary treatment constraints and enable a
step increase in production volumes at both Pelican Lake and
Woodenhouse. 2013 production expected for Pelican Lake remains
unchanged and is targeted to range from 46,000 bbl/d to 50,000 bbl/d. 
- North America light crude oil and NGLs annual production increased
13% in 2012 over 2011 levels as a result of a successful drilling
program consisting of 124 net light crude oil wells. In 2013,
Canadian Natural targets to drill 114 net light crude oil wells, 41
of which are targeting new play developments that were initiated in
2012. The Company continues to advance horizontal multi-frac well
technology in pools across its land base. In addition, 70% of
targeted total drilling will be focused on horizontal wells. 
- Canadian Natural's robust portfolio of thermal in situ projects is
a significant part of the Company's defined plan to transition to a
longer-life, more sustainable asset base with the ability to generate
significant shareholder value for decades to come. The Company
targets to grow thermal in situ production to approximately 500,000
bbl/d of capacity by delivering projects that will add 40,000 bbl/d
of production every two to three years. 
-- At Primrose, total thermal operating costs including energy costs
for Q4/12 were $7.95/bbl. Annual thermal operating costs including
energy costs were $9.69/bbl. Thermal production averaged over 120,000
bbl/d in Q4/12, representing a 19% increase from Q3/12 to Q4/12,
primarily due to new pads at Primrose East entering their production
cycles. Production volumes are targeted to increase by 5% in 2013. 
-- Kirby South Phase 1 is slightly ahead of plan and on budget. All
major equipment and modules have been delivered and installed on site
with overall construction progress ahead of schedule. An update to
the project at the end of Q4/12 is as follows: 
--- Overall project is 81% complete. 
--- Overall construction is 73% complete. 
--- Drilling and Completions are 82% complete. Drilling on the fifth
of seven pads was completed in Q4/12.  In early 2013 the sixth pad
was drilled and the seventh pad is currently being drilled. 
--- First steam-in is targeted for Q4/13 and production is targeted
to ramp up to 40,000 bbl/d in late 2014. 
-- On Kirby North Phase 1, detailed engineering is now in progress.
Construction of the main access road has been completed and site
preparation continues. A stratigraphic ("strat") drilling program
consisting of 50 wells is targeted for Q1/13. First steam-in is
targeted for 2016. Full project sanction is expected in Q3/13. 
- Planned drilling activity for 2013 includes 132 net thermal in situ
wells and 1,022 net crude oil wells, excluding strat test and service
wells. 
- Canadian Natural has an active strat test well drilling program to
delineate the reservoir characteristics for future projects. The
Company targets to drill 463 strat wells in 2013. 


 
 
North America natural gas
                                Three Months Ended           Year Ended
                          --------------------------------------------------
                             Dec 31    Sep 30    Dec 31    Dec 31    Dec 31
                               2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Natural gas production
 (MMcf/d)                     1,113     1,169     1,255     1,198     1,231
----------------------------------------------------------------------------
 
Net wells targeting
 natural gas                      3         9        29        35        86
Net successful wells
 drilled                          3         9        27        35        83
----------------------------------------------------------------------------
  Success rate                  100%      100%       93%      100%       97%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- North America natural gas production for the year averaged 1,198
MMcf/d representing a decrease of 3% from 2011 levels. During Q4/12,
natural gas production averaged 1,113 MMcf/d representing a decrease
of 11% from Q4/11 and 5% from Q3/12. The decrease in production
levels was primarily due to expected production declines reflecting
Canadian Natural's strategic decision to allocate capital to higher
return crude oil projects. As well, the Company shut in a cumulative
total of 40 MMcf/d of natural gas volumes as a result of weakened
natural gas pricing. In Q4/12, production was restricted after ending
fixed processing agreements for certain natural gas volumes to
maintain flexible cost control in response to weakening gas pricing. 
- During 2012, due to weak natural gas pricing, Canadian Natural
reduced its capital expenditures related to natural gas. As a result,
drilling and expansion at Septimus, the Company's liquids rich
Montney play, was deferred into 2013, with the anticipation of
improved pricing. To date, the expansion is on track and is targeted
for completion in late 2013 which will increase targeted natural gas
sales levels from Septimus to 125 MMcf/d, yielding 12,200 bbl/d of
liquids following processing through the plant and deep cut
facilities. 
- Canadian Natural is the second largest producer of natural gas in
Canada and a significant owner and operator of natural gas
infrastructure in Western Canada. The North America Company Gross
proved plus probable natural gas reserve base of 5.57 Tcf generates
operating free cash flow and presents significant upside potential
for natural gas production and value when natural gas prices recover. 
- Canadian Natural has a dominate Montney land position with over one
million high quality net acres, the largest in the industry. In order
to maximize the value of this important asset Canadian Natural has
begun the process to monetize approximately 250,000 net acres
(approximately 390 net sections) of our Montney land base in the
liquids rich fairway in the Graham Kobes area of North East British
Columbia. Under the process Canadian Natural will consider either an
outright sale of the lands or a joint venture partner with LNG
expertise to jointly develop the lands. If this process meets our
internal targets and a transaction is completed, Canadian Natural
will continue to have one of the largest undeveloped Montney land
bases in Canada with lands contained in the two major areas of
Septimus, British Columbia and North West Alberta. 
International Exploration and Production 


 
                                       Three Months Ended            Year
                                                                    Ended
                             -----------------------------------------------
                                Dec 31   Sep 30   Dec 31    Dec 31   Dec 31
                                  2012     2012     2011      2012     2011
----------------------------------------------------------------------------
Crude oil production (bbl/d)
  North Sea                     19,140   19,502   26,769    19,824   29,992
  Offshore A
frica               15,762   17,566   22,726    18,648   23,009
----------------------------------------------------------------------------
Natural gas production
 (MMcf/d)
  North Sea                          1        2        6         2        7
  Offshore Africa                   20       20       19        20       19
----------------------------------------------------------------------------
Net wells targeting crude oil        -        -        -         -      0.9
Net successful wells drilled         -        -        -         -        -
----------------------------------------------------------------------------
  Success rate                       -        -        0%        -        0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- Canadian Natural's international assets provide light crude oil
balance to the Company's diverse portfolio and generated over $200
million of free cash flow in 2012. 
- International crude oil production averaged 38,472 bbl/d during
2012 which was within the Company's previously stated guidance of
38,000 bbl/d - 39,000 bbl/d for the year. Production volumes declined
from 2011 as a result of the suspension of production at Banff/Kyle
(North Sea) due to storm damage in Q4/11, maintenance activities on a
third-party operated pipeline in the North Sea, natural field
declines, and planned maintenance activities at Ninian (North Sea),
Baobab and Espoir (Offshore Africa). 
- Production is targeted to increase by approximately 6% in 2013.
International light oil activities in 2013 will include a ramp up of
drilling operations in the North Sea, the commencement of abandonment
operations at Murchison in the North Sea, and commencement of the
infill drilling program at Espoir, Offshore Africa. 
- The Company continues with the partnering process for South Africa.
Targeted drilling windows are from Q4/13 to Q1/14 and from Q4/14 to
Q1/15. 
North America Oil Sands Mining and Upgrading - Horizon 


 
                                    Three Months Ended        Year Ended
                               ---------------------------------------------
                                  Dec 31   Sep 30   Dec 31   Dec 31   Dec 31
                                    2012     2012     2011     2012     2011
----------------------------------------------------------------------------
Synthetic crude oil production
 (bbl/d)                          83,079   99,205  102,952   86,077   40,434
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
- Horizon Oil Sands achieved average annual SCO production of 86,077
bbl/d in 2012. Production volumes were 113% higher than 2011 volumes
as the reliability of the Horizon plant steadily improved in 2012. 
- Average SCO production of 83,079 bbl/d was achieved at Horizon
during Q4/12. Production decreased 16% from Q3/12 as a result of the
previously announced 12 day planned proactive maintenance activities
completed in October. In late December, additional unplanned
maintenance activities were performed on the OPPs which contributed
to lower quarterly volumes. 
- In January and February 2013, strong performance from Horizon
resulted in average SCO volumes of approximately 113,000 bbl/d and
107,000 bbl/d, respectively. Q1/13 production guidance is targeted to
range from 105,000 bbl/d to 111,000 bbl/d of SCO. 
- The first major turnaround at Horizon is planned for May 2013. To
ensure effective execution of the turnaround and to ensure greater
reliability, the turnaround has been increased from 18 days to 24
days. 2013 annual guidance has not been affected and remains
unchanged at 100,000 bbl/d to 108,000 bbl/d of SCO. 
- Canadian Natural's staged expansion to 250,000 bbl/d of SCO
production capacity continues to progress on track. An update to the
expansion at the end of Q4/12 is as follows: 
-- Overall Horizon expansion is 18% complete. 
-- Reliability - Tranche 2 is 86% complete. This project is targeted
for completion in 2013; an additional of 5,000 bbl/d of production
capacity will be added at completion. 
-- Directive 74 includes technological investment and research into
tailings management. This portion remains on track and is currently
16% complete. 
-- Phase 2A is the coker expansion. The expansion is 47% complete,
and is targeted to add 10,000 bbl/d of production capacity in 2015. 
-- Phase 2B is 8% complete. This phase includes lump sum contracts
for major components such as gas/oil hydrotreatment, froth treatment
and a hydrogen plant. This phase is targeted to add another 45,000
bbl/d of production capacity in 2016. 
-- Phase 3 is on track and engineering is underway. This phase is 8%
complete, and includes the addition of supplementary extraction
trains. This phase is targeted to increase production capacity by
80,000 bbl/d in 2017. 
-- Projects currently under construction are trending at or below
cost estimates. 
MARKETING 


 
                         Three Months Ended                Year Ended
                ------------------------------------------------------------
                     Dec 31      Sep 30      Dec 31      Dec 31      Dec 31
                       2012        2012        2011        2012        2011
----------------------------------------------------------------------------
Crude oil and
 NGLs pricing
  WTI benchmark
   price
   (US$/bbl) (1) $    88.20  $    92.19  $    94.02  $    94.19  $    95.14
  WCS blend
   differential
   from WTI (%)
   (2)                   21%         24%         11%         22%         18%
  SCO price
   (US$/bbl)     $    91.90  $    90.84  $   102.95  $    92.59  $   103.63
  Average
   realized
   pricing
   before risk
   management
   (C$/bbl) (3)  $    64.23  $    67.59  $    85.28  $    70.24  $    77.46
Natural gas
 pricing
  AECO benchmark
   price (C$/GJ) $     2.89  $     2.08  $     3.29  $     2.28  $     3.48
  Average
   realized
   pricing
   before risk
   management
   (C$/Mcf) (3)  $     3.16  $     2.28  $     3.50  $     2.44  $     3.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) West Texas Intermediate ("WTI"). 
(2) Western Canadian Select ("WCS"). 
(3) Average crude oil and NGLs pricing excludes SCO. Pricing is net
of transportation and blending costs, excluding risk management
activities. 
- The WCS heavy crude oil differential ("WCS differential") as a
percent of WTI averaged 22% during 2012 compared with 18% in 2011.
During Q4/12 the WCS differential averaged 21%, in line with the
Company's long term expectations. The Company anticipates continued
volatility in the differential for the first half of 2013 and
narrowing of the differential thereafter as additional heavy oil
conversion and pipeline capacity come on stream. 
- During October and November 2012, the WCS differential averaged 11%
and 16% respectively, widening out to 34% in December 2012 as a
result of unplanned pipeline capacity limitations and
refinery-planned lower crude oil inventories at year-end. During
January and February 2013, the WCS differential widened to average
37% but was partially offset by higher overall WTI pricing. For March
2013, the WCS differential has narrowed to average 29%. 
- Canadian Natural contributed 157,000 bbl/d of its heavy crude oil
stream to the WCS blend in 2012. The Company remains the largest
contributor to the WCS blend, accounting for 53%. 
- During 2012, Canadian natural gas production declined in response
to lower pricing while US natural gas production remained steady
throughout the year. Natural gas pricing recovered to AECO $2.89 in
Q4/12 but benchmark pricing will continue to remain volatile until
the demand from the power generation sector increases enough to
offset strong Nor
th American supply. 
NORTH WEST REDWATER UPGRADING AND REFINING 
During Q4/12, the Redwater Partnership 50,000 bbl/d bitumen refinery
(78,000 bbl/d of bitumen blend) was sanctioned by its owners (50%
Canadian Natural). Work continues on the North West Redwater refinery
and completion is targeted for mid-2016. The Company will also
provide 12,500 bbl/d of bitumen feedstock to the refinery as a toll
payer. There is potential to further expand the downstream capacity
of the North West Redwater refinery from its 50,000 bbl/d of bitumen
facility capacity in Phase 1 to 150,000 bbl/d of bitumen facility
capacity. 
The North West Redwater refinery asset strengthens the Company's
position by providing a competitive return on investment and by
adding 50,000 bbl/d of bitumen conversion capacity in Alberta which
will help reduce volatility in pricing all Western Canadian heavy
crude oil. 
FINANCIAL REVIEW 
The Company continues to implement proven strategies and focuses on
disciplined capital allocation. As a result, the financial position
of Canadian Natural remains strong. Canadian Natural's cash flow
generation, credit facilities, diverse asset base and related capital
expenditure programs, and commodity hedging policy all support a
flexible financial position and provide the right financial resources
for the near, mid and long term. 
- The Company's strategy is to maintain a diverse portfolio balanced
across various commodity types. The Company achieved production of
658,973 BOE/d for Q4/12 with over 97% of production located in G8
countries. 
- Canadian Natural has a strong balance sheet with debt to book
capitalization of 26.0% and debt to EBITDA of 1.2x. At December 31,
2012, long-term debt amounted to $8.7 billion compared with $8.6
billion at December 31, 2011. 
- Canadian Natural maintains significant financial stability and
liquidity represented by approximately $3.66 billion in available
unused bank lines at the end of the 2012. 
- The Company's commodity hedging program protects investment
returns, ensures ongoing balance sheet strength and supports the
Company's cash flow for its capital expenditures programs. Through
the use of collars, the Company has hedged 48% of its forecasted 2013
crude oil volumes; 200,000 bbl/d of crude oil volumes in Q1/13, and
250,000 bbl/d of crude oil volumes in Q2/13, Q3/13 and Q4/13. Details
of the Company's commodity hedging program can be found on the
Company's website at www.cnrl.com. 
- During 2012, Canadian Natural purchased 11,012,700 common shares
for cancellation at a weighted average price of $28.91 per common
share. 
- For 2013, the Board has approved a 19% dividend increase to C$0.125
per quarter, C$0.50 per share annualized.  This will be the
thirteenth consecutive year that the Company has announced an
increased annual dividend distribution representing a compound annual
growth rate of 21% over the period. 
- In addition, the Company's Board of Directors have directed
Management to continue with an active program, subject to market
conditions, to purchase for cancellation common shares under the
Company's Normal Course Issuer Bid at or above the levels of shares
purchased in financial year 2012. 
OUTLOOK 
The Company forecasts 2013 production levels before royalties to
average between 1,085 and 1,145 MMcf/d of natural gas and between
482,000 and 513,000 bbl/d of crude oil and NGLs. Q1/13 production
guidance before royalties is forecast to average between 1,130 and
1,150 MMcf/d of natural gas and between 471,000 and 495,000 bbl/d of
crude oil and NGLs. Detailed guidance on production levels, capital
allocation and operating costs can be found on the Company's website
at www.cnrl.com. 
CORPORATE ANNOUNCEMENTS 
Board of Directors Changes 
James S. Palmer has informed the Company of his decision after 16
years of continuous service as a Director, to not stand for
re-election to the Board of Directors at the Annual and Special
Meeting of Shareholder on May 2, 2013. During Mr. Palmer's tenure
with the Company, Canadian Natural has transitioned from a
conventional oil and natural gas player based in western Canada to
one of the largest independent crude oil and natural gas producers in
the world with both domestic and international operations. Canadian
Natural and the Board would like to thank Mr. Palmer for his valued
wisdom, insight, guidance, leadership and dedication to the Company
and its shareholders since his appointment as a director in 1997. 
Management Changes 
John G. Langille, Vice-Chairman, has announced his decision to retire
from Canadian Natural effective May 2, 2013 immediately following the
Annual and Special Meeting of Shareholders. John has served Canadian
Natural for 37 years in various roles, most recently in the capacity
of Vice-Chairman and prior to that as President. Through John's
untiring efforts and guidance, Canadian Natural has remained focused
on our defined growth plan thereby creating value for our
shareholders through targeting cost effective alternatives to
developing our portfolio of projects and to being one of the most
effective and efficient producers in our industry. Canadian Natural
and the Board would like to thank John for his dedicated service and
loyalty to the Company. 
As part of the Canadian Natural's management stewardship, high
priority is assigned to succession planning to ensure the continued
strength of the Company's leadership team. 
Tim S. McKay, currently Chief Operating Officer, will become
Executive Vice-President and Chief Operating Officer. He will
continue to be responsible for the Canadian Conventional and
International operations, and in addition will now be responsible for
Horizon operations. 
Douglas A. Proll, currently Chief Financial Officer and Senior
Vice-President, Finance will become Executive Vice-President. He will
continue to be a senior member of the Company's Management Committee
and will have direct responsibility for certain non-financial
departments and provide additional leadership in Investor Relations
and other areas of stakeholder relations. 
Corey B. Bieber, Vice-President Finance and Investor Relations will
assume the role of Chief Financial Officer and Senior Vice-President,
Finance. Corey joined Canadian Natural in 2001 and has been
responsible for Treasury and Investor Relations since then and became
a member of the Company's Management Committee in 2009. In his new
role, Corey will be responsible for all aspects of the finance
functions at Canadian Natural. 
The appointments of Mr. McKay, Mr. Bieber and Mr. Proll are effective
March 28, 2013. 
YEAR-END RESERVES 
Determination of Reserves 
For the year ended December 31, 2012 the Company retained Independent
Qualified Reserves Evaluators ("Evaluators"), Sproule Associates
Limited, Sproule International Limited (together as "Sproule") and
GLJ Petroleum Consultants Ltd. ("GLJ"), to evaluate and review all of
the Company's proved and proved plus probable reserves. Sproule
evaluated the Company's North America and International crude oil,
bitumen, natural gas and NGL reserves. GLJ evaluated the Company's
Horizon synthetic crude oil reserves. The Evaluators conducted the
evaluation and review in accordance with the standards contained in
the Canadian Oil and Gas Evaluation Handbook ("COGE Handbook"). The
reserves disclosure is presented in accordance with NI 51-101
requirements using forecast prices and escalated costs. 
The Reserves Committee of the Company's Board of Directors has met
with and carried out independent due diligence procedures with the
Evaluators as to the Company's reserves. 
Corporate Total 
- Company Gross proved crude oil, SCO, bitumen and NGL reserves
increased 6% to 4.33 billion barrels. Company Gross proved natural
gas reserves decreased 7% to 4.14 Tcf. Total proved reserves
increased 4% to 5.02 billion BOE. 
- Company Gross proved plus probable crude oil, SCO, bitumen and NGL
reserves increased 6% to 6.92 billion barrels. Company Gross proved
plus probable natural gas reserves
 decreased 5% to 5.79 Tcf. Total
proved plus probable reserves increased 5% to 7.89 billion BOE. 
- Company Gross proved reserve additions, including acquisitions,
were 404 million barrels of crude oil, SCO, bitumen and NGL and 135
billion cubic feet of natural gas for 426 million BOE. The total
proved reserve replacement ratio was 178%. The total proved reserve
life index is 22.8 years. 
- Company Gross proved plus probable reserve additions, including
acquisitions, were 565 million barrels of crude oil, bitumen, SCO and
NGL and 132 billion cubic feet of natural gas for 587 million BOE.
The total proved plus probable reserve replacement ratio was 246%.
The total proved plus probable reserve life index is 35.8 years. 
- Proved undeveloped crude oil, SCO, bitumen and NGL reserves
accounted for 31% of the corporate total proved reserves and proved
undeveloped natural gas reserves accounted for 4% of the corporate
total proved reserves. 
North America Exploration and Production 
- North America Company Gross proved crude oil, bitumen and NGL
reserves increased 7% to 1.74 billion barrels. Company Gross proved
natural gas reserves decreased 7% to 3.99 Tcf. Total proved BOE
increased 3% to 2.41 billion barrels. 
- North America Company Gross proved plus probable crude oil, bitumen
and NGL reserves increased 16% to 3.08 billion barrels. Company Gross
proved plus probable natural gas reserves decreased 5% to 5.57 Tcf.
Total proved plus probable BOE increased 11% to 4.01 billion barrels. 
- North America Company Gross proved reserve additions and revisions,
including acquisitions, were 230 million barrels of crude oil,
bitumen and NGL and 157 billion cubic feet of natural gas for 256
million BOE. The total proved reserve replacement ratio is 133%. The
total proved reserve life index in 14.3 years. 
- North America Company Gross proved plus probable reserve additions
and revisions, including acquisitions, were 548 million barrels of
crude oil, bitumen and NGL and 174 billion cubic feet of natural gas
for 577 million BOE. The total proved plus probable reserve
replacement ratio was 299%. The total proved plus probable reserve
life index is 23.8 years. 
- Proved undeveloped crude oil, bitumen and NGL reserves accounted
for 38% of the North America total proved reserves and proved
undeveloped natural gas reserves accounted for 8% of the North
America total proved reserves. 
- Thermal oil Company Gross proved reserves increased 9% to 1,066
million barrels primarily due to category transfers from probable
undeveloped to proved undeveloped at Kirby North and new proved
undeveloped additions at Primrose and Wolf Lake. Proved bitumen
reserve additions and revisions were 128 million barrels. Total
proved plus probable bitumen reserves increased 23% to 2,122 million
barrels primarily due to proved plus probable undeveloped additions
at Primrose and Wolf Lake and probable undeveloped additions at
Grouse. 
- Company Gross proved plus probable bitumen reserves additions and
revisions were 432 million barrels. 
North America Oil Sands Mining and Upgrading 
- Company Gross proved synthetic crude oil reserves increased 6% to
2.26 billion barrels. 
- Proved reserve additions were 167 million barrels primarily due to
additional stratigraphic wells drilled in the north pit. 
International Exploration and Production 
- North Sea Company Gross proved reserves decreased 2% to 240 million
BOE primarily due to production. North Sea Company Gross proved plus
probable reserves are 349 million BOE. 
- Offshore Africa Company Gross proved reserves decreased 7% to 115
million BOE primarily due to production. Offshore Africa Company
Gross proved plus probable reserves are 177 million BOE. 
Summary of Company Gross Crude Oil, Bitumen, Natural Gas & NGL
Reserves 
As of December 31, 2012 
Forecast Prices and Costs 


 
                                                          Pelican    Bitumen
                                  Light and    Primary      Lake    (Thermal
                                 Medium Oil  Heavy Oil  Heavy Oil      Oil)
                                      MMbbl      MMbbl      MMbbl      MMbbl
----------------------------------------------------------------------------
North America
Proved
 Developed Producing                     92         85        217        238
 Developed Non-Producing                  2         23         11        104
 Undeveloped                             19         96         39        724
----------------------------------------------------------------------------
Total Proved                            113        204        267      1,066
Probable                                 51         80        105      1,056
----------------------------------------------------------------------------
Total Proved plus Probable              164        284        372      2,122
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
North Sea
Proved
 Developed Producing                     49
 Developed Non-Producing                 14
 Undeveloped                            164
----------------------------------------------------------------------------
Total Proved                            227
Probable                                105
----------------------------------------------------------------------------
Total Proved plus Probable              332
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Offshore Africa
Proved
 Developed Producing                     65
 Developed Non-Producing                  -
 Undeveloped                             38
----------------------------------------------------------------------------
Total Proved                            103
Probable                                 55
----------------------------------------------------------------------------
Total Proved plus Probable              158
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Total Company
Proved
 Developed Producing                    206         85        217        238
 Developed Non-Producing                 16         23         11        104
 Undeveloped                            221         96         39        724
----------------------------------------------------------------------------
Total Proved                            443        204        267      1,066
Probable                                211         80        105      1,056
----------------------------------------------------------------------------
Total Proved plus Probable              654        284        372      2,122
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                   
                                              Barrels of
                                  Synthetic          Natural Gas        Oil
                                  Crude Oil   Natural    Liquids Equivalent
                                      MMbbl   Gas Bcf      MMbbl      MMBOE
---------------------------------------------------------------------------
North America
Proved
 Developed Producing                  1,837     2,664         53      2,966
 Developed Non-Producing                  -       213          3        178
 Undeveloped                            418     1,108         38      1,519
---------------------------------------------------------------------------
Total Proved                          2,255     3,985         94      4,663
Probable                              1,096     1,589         44      2,697
---------------------------------------------------------------------------
Total Proved plus Probable            3,351     5,574        138      7,360
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
North Sea
Proved
 Developed Producing                                3                    49
 Developed Non-Producing                           55                    23
 Undeveloped                                       24                   168
---------------------------------------------------------------------------
Total Proved                                       82                   240
Probable                                           20                   109
---------------------------------------------------------------------------
Total Proved plus Probable                        102                   349
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
Offshore Africa
Proved
 Developed Producing                               56                    75
 Developed Non-Producing                            -                     -
 Undeveloped                                       13                    40
---------------------------------------------------------------------------
Total Proved                                       69                   115
Probable                                           42                    62
---------------------------------------------------------------------------
Total Proved plus Probable                        111                   177
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
Total Company
Proved
 Developed Producing                  1,837     2,723         53      3,090
 Developed Non-Producing                  -       268          3        201
 Undeveloped                            418     1,145         38      1,727
---------------------------------------------------------------------------
Total Proved                          2,255     4,136         94      5,018
Probable                              1,096     1,651         44      2,868
---------------------------------------------------------------------------
Total Proved plus Probable            3,351     5,787        138      7,886
---------------------------------------------------------------------------
---------------------------------------------------------------------------

 
Summary of Company Net Crude Oil, Bitumen, Natural Gas & NGL Reserves 
As of December 31, 2012 
Forecast Prices and Costs 


 
                                                          Pelican    Bitumen
                                  Light and    Primary      Lake    (Thermal
                                 Medium Oil  Heavy Oil  Heavy Oil      Oil)
                                      MMbbl      MMbbl      MMbbl      MMbbl
----------------------------------------------------------------------------
North America
Proved
 Developed Producing                     81         71        170        179
 Developed Non-Producing                  1         19         10         83
 Undeveloped                             16         82         32        564
----------------------------------------------------------------------------
Total Proved                             98        172        212        826
Probable                                 42         64         75        801
----------------------------------------------------------------------------
Total Proved plus Probable              140        236        287      1,627
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
North Sea
Proved
 Developed Producing                     49
 Developed Non-Producing                 14
 Undeveloped                            164
----------------------------------------------------------------------------
Total Proved                            227
Probable                                105
----------------------------------------------------------------------------
Total Proved plus Probable              332
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Offshore Africa
Proved
 Developed Producing                     55
 Developed Non-Producing                  0
 Undeveloped                             30
----------------------------------------------------------------------------
Total Proved                             85
Probable                                 42
----------------------------------------------------------------------------
Total Proved plus Probable              127
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Total Company
Proved
 Developed Producing                    185         71        170        179
 Developed Non-Producing                 15         19         10         83
 Undeveloped                            210         82         32        564
----------------------------------------------------------------------------
Total Proved                            410        172        212        826
Probable                                189         64         75        801
----------------------------------------------------------------------------
Total Proved plus Probable              599        236        287      1,627
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                                                 Barrels of
                                  Synthetic          Natural Gas        Oil
                                  Crude Oil   Natural    Liquids Equivalent
                                      MMbbl   Gas Bcf      MMbbl      MMBOE
---------------------------------------------------------------------------
North America
Proved
 Developed Producing                  1,516     2,394         37      2,453
 Developed Non-Producing                  -       178          2        145
 Undeveloped                            375       968         30      1,260
---------------------------------------------------------------------------
Total Proved                          1,891     3,540         69      3,858
Probable                                835     1,367         34      2,079
---------------------------------------------------------------------------
Total Proved plus Probable            2,726     4,907        103      5,937
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
North Sea
Proved
 Developed Producing                                3                    49
 Developed Non-Producing                           55                    23
 Undeveloped                                       24                   168
---------------------------------------------------------------------------
Total Proved                                       82                   240
Probable                                           20                   109
---------------------------------------------------------------------------
Total Proved plus Probable                        102                   349
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
Offshore Africa
Proved
 Developed Producing                               39                    61
 Developed Non-Producing                            -                     -
 Undeveloped                                        9                    32
---------------------------------------------------------------------------
Total Proved    
                                   48                    93
Probable                                           28                    47
---------------------------------------------------------------------------
Total Proved plus Probable                         76                   140
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
Total Company
Proved
 Developed Producing                  1,516     2,436         37      2,563
 Developed Non-Producing                  -       233          2        168
 Undeveloped                            375     1,001         30      1,460
---------------------------------------------------------------------------
Total Proved                          1,891     3,670         69      4,191
Probable                                835     1,415         34      2,235
---------------------------------------------------------------------------
Total Proved plus Probable            2,726     5,085        103      6,426
---------------------------------------------------------------------------
---------------------------------------------------------------------------

 
Reconciliation of Company Gross Reserves by Product 
As of December 31, 2012 
Forecast Prices and Costs 


 
PROVED
                                                        Pelican     Bitumen
                              Light and     Primary       Lake     (Thermal
North America                Medium Oil   Heavy Oil   Heavy Oil       Oil)
                                  MMbbl       MMbbl       MMbbl       MMbbl
----------------------------------------------------------------------------
December 31, 2011                   114         175         276         974
----------------------------------------------------------------------------
Discoveries                           -           -           -           -
Extensions                            4          24      
     1          68
Infill Drilling                       5          20           -          10
Improved Recovery                     -           -           5           -
Acquisitions                          1           -           -           -
Dispositions                          -           -           -           -
Economic Factors                      -           -           -           -
Technical Revisions                   4          31          (1)         50
Production                          (15)        (46)        (14)        (36)
----------------------------------------------------------------------------
December 31, 2012                   113         204         267       1,066
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
North Sea
 
----------------------------------------------------------------------------
December 31, 2011                   228
----------------------------------------------------------------------------
Discoveries                           -
Extensions                            -
Infill Drilling                       -
Improved Recovery                     -
Acquisitions                          -
Dispositions                          -
Economic Factors                      4
Technical Revisions                   2
Production                         
  (7)
----------------------------------------------------------------------------
December 31, 2012                   227
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
Offshore Africa
 
----------------------------------------------------------------------------
December 31, 2011                   109
----------------------------------------------------------------------------
Discoveries                           -
Extensions                            -
Infill Drilling                       1
Improved Recovery                     -
Acquisitions                          -
Dispositions                          -
Economic Factors                      -
Technical Revisions                   -
Production                           (7)
----------------------------------------------------------------------------
December 31, 2012                   103
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
Total Company
 
----------------------------------------------------------------------------
December 31, 2011                   451         175         276         974
----------------------------------------------------------------------------
Discoveries                           -        
  -            -           -
Extensions                            4          24           1          68
Infill Drilling                       6          20           -          10
Improved Recovery                     -           -           5           -
Acquisitions                          1           -           -           -
Dispositions                          -           -           -           -
Economic Factors                      4           -           -           -
Technical Revisions                   6          31          (1)         50
Production                          (29)        (46)        (14)        (36)
----------------------------------------------------------------------------
December 31, 2012                   443         204         267       1,066
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
PROVED
                                                                Barrels of
                              Synthetic            Natural Gas         Oil
North America                 Crude Oil    Natural     Liquids  Equivalent
                                  MMbbl    Gas Bcf       MMbbl       MMBOE
---------------------------------------------------------------------------
December 31, 2011                 2,119      4,266          95       4,464
---------------------------------------------------------------------------
Discoveries                           -          6           -           1
Extensions                            -         52           2         107
Infill Drilling                       -         16           1          39
Improved Recovery                     -          -           -           5
Acquisitions                          -         43           1           9
Dispositions                          -         (1)          -           -
Economic Factors                     14        (38)         (1)          7
Technical Revisions                 153         79           5         255
Production                          (31)      (438)         (9)       (224)
---------------------------------------------------------------------------
December 31, 2012                 2,255      3,985          94       4,663
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
 
North Sea
 
---------------------------------------------------------------------------
December 31, 2011                               98                     244
---------------------------------------------------------------------------
Discoveries                                      -                       -
Extensions                                       -                       -
Infill Drilling                                  -                       -
Improved Recovery                                -                       -
Acquisitions                                     -                       -
Dispositions                                     -                       -
Economic Factors                                 1                       4
Technical Revisions                            (16)                     (1)
Production                                      (1)                     (7)
---------------------------------------------------------------------------
December 31, 2012                               82                     240
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
 
Offshore Africa
 
---------------------------------------------------------------------------
December 31, 2011                               83                     123
---------------------------------------------------------------------------
Discoveries                                      -                       -
Extensions                                       -                       -
Infill Drilling                                  -                       1
Improved Recovery                                -                       -
Acquisitions                                     -                       -
Dispositions                                     -                       -
Economic Factors                                 -                       -
Technical Revisions                             (7)                     (1)
Production                                      (7)                     (8)
---------------------------------------------------------------------------
December 31, 2012                               69                     115
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
 
Total Company
 
---------------------------------------------------------------------------
December 31, 2011                 2,119      4,447          95       4,831
---------------------------------------------------------------------------
Discoveries                           -          6           -           1
Extensions                            -         52           2         107
Infill Drilling                       -         16           1          40
Improved Recovery                     -          -           -           5
Acquisitions                          -         43           1           9
Dispositions                          -         (1)          -           -
Economic Factors                     14        (37)         (1)         11
Technical Revisions                 153         56           5         253
Production                          (31)      (446)         (9)       (239)
---------------------------------------------------------------------------
December 31, 2012                 2,255      4,136          94       5,018
---------------------------------------------------------------------------
---------------------------------------------------------------------------

 
Reconciliation of Company Gross Reserves by Product 
As of December 31, 2012 
Forecast Prices and Costs 


 
PROBABLE
                                                         Pelican     Bitumen
                               Light and     Primary       Lake     (Thermal
North America                 Medium Oil   Heavy Oil   Heavy Oil       Oil)
                                   MMbbl       MMbbl       MMbbl       MMbbl
----------------------------------------------------------------------------
December 31, 2011                     41          74         112         752
----------------------------------------------------------------------------
Discoveries                            -           -           -           -
Extensions                             4          10           -         277
Infill Drilling                        6           8           -           5
Improved Recovery                      -           -           3           -
Acquisitions                           -           -           -           -
Dispositions                           -           
-           -           -
Economic Factors                       -           -           -           -
Technical Revisions                    -         (12)        (10)         22
Production                             -           -           -           -
----------------------------------------------------------------------------
December 31, 2012                     51          80         105       1,056
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
North Sea
 
----------------------------------------------------------------------------
December 31, 2011                    121
----------------------------------------------------------------------------
Discoveries                            -
Extensions                             -
Infill Drilling                        -
Improved Recovery                      -
Acquisitions                           -
Dispositions                           -
Economic Factors                      (4)
Technical Revisions                  (12)
Production                             -
----------------------------------------------------------------------------
December 31, 2012                    105
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
Offshore Africa
 
----------------------------------------------------------------------------
December 31, 2011                     56
----------------------------------------------------------------------------
Discoveries                            -
Extensions                             -
Infill Drilling                        1
Improved Recovery                      -
Acquisitions                           -
Dispositions                           -
Economic Factors                       -
Technical Revisions                   (2)
Production                             -
----------------------------------------------------------------------------
December 31, 2012                     55
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
Total Company
 
----------------------------------------------------------------------------
December 31, 2011                    218          74         112         752
----------------------------------------------------------------------------
Discoveries                            -           -           -           -
Extensions                             4          10           -         277
Infill Drilling                        7           8           -           5
Improved Recovery                      -           -           3           -
Acquisitions                           -           -           -           -
Dispositions                           -           -           -           -
Economic Factors                      (4)          -           -           -
Technical Revisions                  (14)        (12)        (10)         22
Production                             -           -           -           -
----------------------------------------------------------------------------
December 31, 2012                    211          80         105       1,056
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
PROBABLE
                                                                Barrels of
                               Synthetic            Natural Gas        Oil
North America                  Crude Oil    Natural     Liquids Equivalent
                                   MMbbl    Gas Bcf       MMbbl      MMBOE
---------------------------------------------------------------------------
December 31, 2011                  1,236      1,572          39      2,516
---------------------------------------------------------------------------
Discoveries                            -          5           -          1
Extensions                             -         38           3        301
Infill Drilling                        -         10           -         20
Improved Recovery                      -          -           -          3
Acquisitions                           -         15           -          3
Dispositions                           -         (2)          -         (1)
Economic Factors                     (11)        (2)          -        (11)
Technical Revisions                 (129)       (47)          2       (135)
Production                             -          -           -          -
---------------------------------------------------------------------------
December 31, 2012                  1,096      1,589          44      2,697
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
 
North Sea
 
---------------------------------------------------------------------------
December 31, 2011                                36                    127
---------------------------------------------------------------------------
Discoveries                                       -                      -
Extensions                                        -                      -
Infill Drilling                                   -                      -
Improved Recovery                                 -                      -
Acquisitions                                      -                      -
Dispositions                                      -                      -
Economic Factors                                 (1)                    (4)
Technical Revisions                             (15)                   (14)
Production                                        -                      -
---------------------------------------------------------------------------
December 31, 2012                                20                    109
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
 
Offshore Africa
 
---------------------------------------------------------------------------
December 31, 2011                                46                     64
---------------------------------------------------------------------------
Discoveries                                       -                      -
Extensions                                        -                      -
Infill Drilling                                   -                      1
Improved Recovery                                 -                      -
Acquisitions                                      -                      -
Dispositions                                      -                      -
Economic Factors                                  -                      -
Technical Revi
sions                              (4)                    (3)
Production                                        -                      -
---------------------------------------------------------------------------
December 31, 2012                                42                     62
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
 
Total Company
 
---------------------------------------------------------------------------
December 31, 2011                  1,236      1,654          39      2,707
---------------------------------------------------------------------------
Discoveries                           -           5           -          1
Extensions                            -          38           3        301
Infill Drilling                       -          10           -         21
Improved Recovery                     -                       -          3
Acquisitions                          -          15           -          3
Dispositions                          -          (2)          -         (1)
Economic Factors                     (11)        (3)          -        (15)
Technical Revisions                 (129)       (66)          2       (152)
Production                             -          -           -          -
---------------------------------------------------------------------------
December 31, 2012                  1,096      1,651          44      2,868
---------------------------------------------------------------------------
---------------------------------------------------------------------------

 
Reconciliation of Company Gross Reserves by Product 
As of December 31, 2012 
Forecast Prices and Costs 


 
PROVED PLUS PROBABLE
                                                        Pelican     Bitumen
                              Light and     Primary       Lake     (Thermal
North America                Medium Oil   Heavy Oil   Heavy Oil       Oil)
                                  MMbbl       MMbbl       MMbbl       MMbbl
----------------------------------------------------------------------------
December 31, 2011                   155         249         388       1,726
----------------------------------------------------------------------------
Discoveries                           -           -           -           -
Extensions                            8          34           1         345
Infill Drilling                      11          28           -          15
Improved Recovery                     -           -           8           -
Acquisitions                          1           -           -           -
Dispositions                          -           -           -           -
Economic Factors                      -           -           -           -
Technical Revisions                   4          19         (11)         72
Production                          (15)        (46)        (14)        (36)
----------------------------------------------------------------------------
December 31, 2012                   164         284         372       2,122
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
North Sea
 
----------------------------------------------------------------------------
December 31, 2011                   349
----------------------------------------------------------------------------
Discoveries                           -
Extensions                            -
Infill Drilling                       -
Improved Recovery                     -
Acquisitions                          -
Dispositions                          -
Economic Factors                      -
Technical Revisions                 (10)
Production                           (7)
----------------------------------------------------------------------------
December 31, 2012                   332
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
Offshore Africa
 
----------------------------------------------------------------------------
December 31, 2011                   165
----------------------------------------------------------------------------
Discoveries                           -
Extensions                            -
Infill Drilling                       2
Improved Recovery                     -
Acquisitions                          -
Dispositions                          -
Economic Factors                      -
Technical Revisions                  (2)
Production                           (7)
----------------------------------------------------------------------------
December 31, 2012                   158
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
Total Company
 
----------------------------------------------------------------------------
December 31, 2011                   669         249         388       1,726
----------------------------------------------------------------------------
Discoveries                           -           -           -           -
Extensions                            8          34           1         345
Infill Drilling                      13          28           -          15
Improved Recovery                     -           -           8           -
Acquisitions                          1           -           -           -
Dispositions                          -           -           -           -
Economic Factors                      -           -           -           -
Technical Revisions                  (8)         19         (11)         72
Production                          (29)        (46)        (14)        (36)
----------------------------------------------------------------------------
December 31, 2012                   654         284         372       2,122
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
PROVED PLUS PROBABLE
                                                                Barrels of
                              Synthetic            Natural Gas         Oil
North America                 Crude Oil    Natural     Liquids  Equivalent
                                  MMbbl    Gas Bcf       MMbbl       MMBOE
---------------------------------------------------------------------------
December 31, 2011                 3,355      5,838         134       6,980
---------------------------------------------------------------------------
Discoveries                           -         11           -           2
Extensions                            -         90           5         408
Infill Drilling                       -         26           1          59
Improved Recovery                     -          -           -           8
Acquisitions                          -         58           1          12
Dispositions                          -         (3)          -          (1)
Economic Factors                      3        (40)         (1)         (4)
Technical Revisions                  24         32           7         120
Production                          (31)      (438)         (9)       (224)
---------------------------------------------------------------------------
December 31, 2012                 3,351      5,574         138       7,360
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
 
North Sea
 
---------------------------------------------------------------------------
December 31, 2011                              134                     371
---------------------------------------------------------------------------
Discoveries                                      -                       -
Extensions                                       -                       -
Infill Drilling                                  -                       -
Improved Recovery                                -                       -
Acquisitions                                     -                       -
Dispositions                                     -                       -
Economic Factors                                 -                       -
Technical Revisions                            (31)                    (15)
Production                                      (1)                     (7)
---------------------------------------------------------------------------
December 31, 2012                              102                     349
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
 
Offshore Africa
 
---------------------------------
------------------------------------------
December 31, 2011                              129                     187
---------------------------------------------------------------------------
Discoveries                                      -                       -
Extensions                                       -                       -
Infill Drilling                                  -                       2
Improved Recovery                                -                       -
Acquisitions                                     -                       -
Dispositions                                     -                       -
Economic Factors                                 -                       -
Technical Revisions                            (11)                     (4)
Production                                      (7)                     (8)
---------------------------------------------------------------------------
December 31, 2012                              111                     177
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
 
Total Company
 
---------------------------------------------------------------------------
December 31, 2011                 3,355      6,101         134       7,538
---------------------------------------------------------------------------
Discoveries                           -         11           -           2
Extensions                            -         90           5         408
Infill Drilling                       -         26           1          61
Improved Recovery                     -          -           -           8
Acquisitions                          -         58           1          12
Dispositions                          -         (3)          -          (1)
Economic Factors                      3        (40)         (1)         (4)
Technical Revisions                  24        (10)          7         101
Production                          (31)      (446)         (9)       (239)
---------------------------------------------------------------------------
December 31, 2012                 3,351      5,787         138       7,886
---------------------------------------------------------------------------
---------------------------------------------------------------------------

 
(1) Company Gross reserves are working interest share before
deduction of royalties and excluding any royalty interests. 
(2) Company Net reserves are working interest share after deduction
of royalties and including any royalty interests. 
(3) Forecast pricing assumptions utilized by the independent
qualified reserves evaluators in the reserve estimates were provided
by Sproule Associates Limited: 


 
                                                                   Average
                                                                     annual
                                                                   increase
                  2013      2014      2015      2016      2017   thereafter
----------------------------------------------------------------------------
Crude oil and
 NGLs
  WTI at
   Cushing
   (US$/bbl)    $   89.63 $   89.93 $   88.29 $   95.52 $   96.96       1.5%
  Western
   Canada
   Select
   (C$/bbl)     $   69.33 $   74.57 $   73.21 $   80.17 $   81.37       1.5%
  Edmonton Par
   (C$/bbl)     $   84.55 $   89.84 $   88.21 $   95.43 $   96.87       1.5%
  Edmonton
   Pentanes+
   (C$/bbl)     $   90.53 $   96.19 $   94.44 $  102.18 $  103.71       1.5%
  North Sea
   Brent
   (US$/bbl)    $  106.42 $  101.65 $   97.56 $  105.07 $  106.65       1.5%
----------------------------------------------------------------------------
Natural gas
  AECO
   (C$/MMBtu)   $    3.31 $    3.72 $    3.91 $    4.70 $    5.32       1.5%
  BC Westcoast
   Station 2
   (C$/MMBtu)   $    3.25 $    3.66 $    3.85 $    4.64 $    5.26       1.5%
  Henry Hub
   Louisiana
   (US$/MMBtu)  $    3.65 $    4.06 $    4.24 $    5.04 $    5.66       1.5%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
A foreign exchange rate of 1.001 US$/Cdn$ was used in the 2012
evaluation. 
(4) Reserve additions are comprised of all categories of Company
Gross reserve changes, exclusive of production. 
(5) Reserve replacement ratio is the Company Gross reserve additions
divided by the Company Gross production in the same period. 
(6) A barrel of oil equivalent ("BOE") is derived by converting six
thousand cubic feet of natural gas to one barrel of crude oil (6
Mcf:1 bbl). This conversion may be misleading, particularly if used
in isolation, since the 6 Mcf:1 bbl ratio is based on an energy
equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead. In
comparing the value ratio using current crude oil prices relative to
natural gas prices, the 6 Mcf:1 bbl conversion ratio may be
misleading as an indication of value. 
MANAGEMENT'S DISCUSSION AND ANALYSIS 
Forward-Looking Statements 
Certain statements relating to Canadian Natural Resources Limited
(the "Company") in this document or documents incorporated herein by
reference constitute forward-looking statements or information
(collectively referred to herein as "forward-looking statements")
within the meaning of applicable securities legislation.
Forward-looking statements can be identified by the words "believe",
"anticipate", "expect", "plan", "estimate", "target", "continue",
"could", "intend", "may", "potential", "predict", "should", "will",
"objective", "project", "forecast", "goal", "guidance", "outlook",
"effort", "seeks", "schedule", "proposed" or expressions of a similar
nature suggesting future outcome or statements regarding an outlook.
Disclosure related to expected future commodity pricing, forecast or
anticipated production volumes, royalties, operating costs, capital
expenditures, income tax expenses and other guidance provided
throughout this Management's Discussion and Analysis ("MD&A"),
constitute forward-looking statements. Disclosure of plans relating
to and expected results of existing and future developments,
including but not limited to the Horizon Oil Sands operations and
future expansions, Primrose thermal projects, Pelican Lake water and
polymer flood project, the Kirby Thermal Oil Sands Project,
construction of the proposed Keystone XL Pipeline from Hardisty,
Alberta to the US Gulf Coast, the proposed Kinder Morgan Trans
Mountain pipeline expansion from Edmonton, Alberta to Vancouver,
British Columbia, and the construction and future operations of the
North West Redwater bitumen upgrader and refinery also constitute
forward-looking statements. This forward-looking information is based
on annual budgets and multi-year forecasts, and is reviewed and
revised throughout the year as necessary in the context of targeted
financial ratios, project returns, product pricing expectations and
balance in project risk and time horizons. These statements are not
guarantees of future performance and are subject to certain risks.
The reader should not place undue reliance on these forward-looking
statements as there can be no assurances that the plans, initiatives
or expectations upon which they are based will occur. 
In addition, statements relating to "reserves" are deemed to be
forward-looking statements as they involve the implied assessment
based on certain estimates and assumptions that the reserves
described can be profitably produced in the future. There are
numerous uncertainties inherent in estimating quantities of proved
and proved plus probable crude oil, natural gas and natural gas
liquids ("NGLs") reserves and in projecting future rates of
production and the timing of development expenditures. The total
amount or timing of actual future production may vary significantly
from reserve and product
ion 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 and year ended
December 31, 2012 and the MD&A and the audited consolidated financial
statements for the year ended December 31, 2011. 
All dollar amounts are referenced in millions of Canadian dollars,
except where noted otherwise. The Company's consolidated financial
statements for the period ended December 31, 2012 and this MD&A have
been prepared in accordance with International Financial Reporting
Standards ("IFRS") as issued by the International Accounting
Standards Board. This MD&A includes references to financial measures
commonly used in the crude oil and natural gas industry, such as
adjusted net earnings from operations, cash flow from operations, and
cash production costs. These financial measures are not defined by
IFRS and therefore are referred to as non-GAAP measures. The non-GAAP
measures used by the Company may not be comparable to similar
measures presented by other companies. The Company uses these
non-GAAP measures to evaluate its performance. The non-GAAP measures
should not be considered an alternative to or more meaningful than
net earnings, as determined in accordance with IFRS, as an indication
of the Company's performance. The non-GAAP measures adjusted net
earnings from operations and cash flow from operations are reconciled
to net earnings, as determined in accordance with IFRS, in the
"Financial Highlights" section of this MD&A. The derivation of cash
production costs is included in the "Operating Highlights - Oil Sands
Mining and Upgrading" section of this MD&A. The Company also presents
certain non-GAAP financial ratios and their derivation in the
"Liquidity and Capital Resources" section of this MD&A. 
A Barrel of Oil Equivalent ("BOE") is derived by converting six
thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of
crude oil (6 Mcf:1 bbl). This conversion may be misleading,
particularly if used in isolation, since the 6 Mcf:1 bbl ratio is
based on an energy equivalency conversion method primarily appli
cable
at the burner tip and does not represent a value equivalency at the
wellhead. In comparing the value ratio using current crude oil prices
relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may
be misleading as an indication of value. In addition, for the
purposes of this MD&A, crude oil is defined to include the following
commodities: light and medium crude oil, primary heavy crude oil,
Pelican Lake heavy crude oil, bitumen (thermal oil), and synthetic
crude oil. 
Production volumes and per unit statistics are presented throughout
this MD&A on a "before royalty" or "gross" basis, and realized prices
are net of transportation and blending costs and exclude the effect
of risk management activities. Production on an "after royalty" or
"net" basis is also presented for information purposes only. 
The following discussion refers primarily to the Company's financial
results for the three months and year ended December 31, 2012 in
relation to the comparable periods in 2011 and the third quarter of
2012. 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, 2011, is available
on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov. This MD&A is
dated March 6, 2013. 
FINANCIAL HIGHLIGHTS 


 
 
($ millions, except per common share amounts)
                             Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
                            2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Product sales         $    4,059 $    3,978 $    4,788 $   16,195 $   15,507
Net earnings          $      352 $      360 $      832 $    1,892 $    2,643
  Per common share -
   basic              $     0.32 $     0.33 $     0.76 $     1.72 $     2.41
  - diluted           $     0.32 $     0.33 $     0.76 $     1.72 $     2.40
Adjusted net earnings
 from operations (1)  $      359 $      353 $      972 $    1,618 $    2,540
  Per common share -
   basic              $     0.33 $     0.33 $     0.89 $     1.48 $     2.32
  - diluted           $     0.33 $     0.32 $     0.88 $     1.47 $     2.30
Cash flow from
 operations (2)       $    1,548 $    1,431 $    2,158 $    6,013 $    6,547
  Per common share -
   basic              $     1.41 $     1.31 $     1.97 $     5.48 $     5.98
  - diluted           $     1.41 $     1.30 $     1.96 $     5.47 $     5.94
Capital expenditures,
 net of dispositions  $    1,767 $    1,621 $    1,909 $    6,308 $    6,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Adjusted net earnings from operations is a non-GAAP measure that
represents net earnings adjusted for certain items of a
non-operational nature. The Company evaluates its performance based
on adjusted net earnings from operations. The reconciliation
"Adjusted Net Earnings from Operations" presented below lists the
after-tax effects of certain items of a non-operational nature that
are included in the Company's financial results. Adjusted net
earnings from operations may not be comparable to similar measures
presented by other companies. 
(2) Cash flow from operations is a non-GAAP measure that represents
net earnings adjusted for non-cash items before working capital
adjustments. The Company evaluates its performance based on cash flow
from operations. The Company considers cash flow from operations a
key measure as it demonstrates the Company's ability to generate the
cash flow necessary to fund future growth through capital investment
and to repay debt. The reconciliation "Cash Flow from Operations"
presented lists certain non-cash items that are included in the
Company's financial results. Cash flow from operations may not be
comparable to similar measures presented by other companies. 
Adjusted Net Earnings from Operations 


 
                         Three Months Ended                Year Ended
                ------------------------------------------------------------
                     Dec 31      Sep 30      Dec 31      Dec 31      Dec 31
($ millions)           2012        2012        2011        2012        2011
----------------------------------------------------------------------------
Net earnings as
 reported        $      352  $      360  $      832  $    1,892  $    2,643
Share-based
 compensation,
 net of tax (1)         (41)         49         207        (214)       (102)
Unrealized risk
 management loss
 (gain), net of
 tax (2)                  4          22          50         (37)        (95)
Unrealized
 foreign
 exchange loss
 (gain), net of
 tax (3)                254        (136)       (117)        129         215
Realized foreign
 exchange gain
 on repayment of
 US dollar debt
 securities (4)        (210)          -           -        (210)       (225)
Effect of
 statutory tax
 rate and other
 legislative
 changes on
 deferred income
 tax liabilities
 (5)                      -          58           -          58         104
----------------------------------------------------------------------------
Adjusted net
 earnings from
 operations      $      359  $      353  $      972  $    1,618  $    2,540
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) The Company's employee stock option plan provides for a cash
payment option. Accordingly, the fair value of the outstanding vested
options is recorded as a liability on the Company's balance sheets
and periodic changes in the fair value are recognized in net earnings
or are capitalized to Oil Sands Mining and Upgrading construction
costs. 
(2) Derivative financial instruments are recorded at fair value on
the balance sheets, with changes in the fair value of non-designated
hedges recognized in net earnings. The amounts ultimately realized
may be materially different than reflected in the financial
statements due to changes in prices of the underlying items hedged,
primarily crude oil and natural gas. 
(3) Unrealized foreign exchange gains and losses result primarily
from the translation of US dollar denominated long-term debt to
period-end exchange rates, partially offset by the impact of cross
currency swaps, and are recognized in net earnings. 
(4) During the fourth quarter of 2012, the Company repaid US$350
million of 5.45% unsecured notes. During the third quarter of 2011,
the Company repaid US$400 million of 6.70% unsecured notes. 
(5) All substantively enacted adjustments in applicable income tax
rates and other legislative changes are applied to underlying assets
and liabilities on the Company's balance sheets in determining
deferred income tax assets and liabilities. The impact of these tax
rate and other legislative changes is recorded in net earnings during
the period the legislation is substantively enacted. During the third
quarter of 2012, the UK government enacted legislation to restrict
the combined corporate and supplementary income tax rate relief on UK
North Sea decommissioning expenditures to 50%, resulting in an
increase in the Company's deferred income tax liability of $58
million. During the first quarter of 2011, the UK government enacted
legislation to increase the corporate income tax rate charged on
profits from UK North Sea crude oil and natural gas production from
50% to 62%. The Company's deferred income tax liability was increased
by $104 million with respect to this tax rate change. 
Cash Flow from Operations 


 
                         Three Months Ended                Year Ended
                ------------------------------------------------------------
                     Dec 31      Sep 30      Dec 31      Dec 31      Dec 31
($ millions)           2012        2012        2011        2012        2011
----------------------------------------------------------------------------
Net earnings     $      352  $      360  $      832  $    1,892  $    2,643
Non-cash items:
  Depletion,
   depreciation
   and
   amortization       1,213       1,056         998       4,328       3,604
  Share-based
   compensation         (41)         49         207        (214)       (102)
  Asset
   retirement
   obligation
   accretion             38          38          33         151         130
  Unrealized
   risk
   management
   loss (gain)            8          34          58         (42)       (128)
  Unrealized
   foreign
   exchange loss
   (gain)               254        (136)       (117)        129         215
  Realized
   foreign
   exchange gain
   on repayment
   of US dollar
   debt
   securities          (210)          -           -        (210)       (225)
  Equity loss
   from 
jointly
   controlled
   entity                 3           1           -           9           -
  Deferred
   income tax
   (recovery)
   expense              (69)         29         144         (30)        407
  Horizon asset
   impairment
   provision              -           -           -           -         396
Insurance
 recovery -
 property damage          -           -           3           -        (393)
----------------------------------------------------------------------------
Cash flow from
 operations      $    1,548  $    1,431  $    2,158  $    6,013  $    6,547
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS 
Net earnings for the year ended December 31, 2012 were $1,892 million
compared with $2,643 million for the year ended December 31, 2011.
Net earnings for the year ended December 31, 2012 included net
after-tax income of $274 million compared with $103 million for the
year ended December 31, 2011 related to the effects of share-based
compensation, risk management activities, fluctuations in foreign
exchange rates, the impact of a realized foreign exchange gain on
repayment of long-term debt and the impact of statutory tax rate and
other legislative changes on deferred income tax liabilities.
Excluding these items, adjusted net earnings from operations for the
year ended December 31, 2012 were $1,618 million compared with $2,540
million for the year ended December 31, 2011. 
Net earnings for the fourth quarter of 2012 were $352 million
compared with $832 million for the fourth quarter of 2011 and $360
million for the third quarter of 2012. Net earnings for the fourth
quarter of 2012 included net after-tax expenses of $7 million
compared with $140 million for the fourth quarter of 2011 and net
after-tax income of $7 million for the third quarter of 2012 related
to the effects of share-based compensation, risk management
activities, fluctuations in foreign exchange rates, the impact of a
realized foreign exchange gain on repayment of long-term debt and the
impact of statutory tax rate and other legislative changes on
deferred income tax liabilities. Excluding these items, adjusted net
earnings from operations for the fourth quarter of 2012 were $359
million compared with $972 million for the fourth quarter of 2011 and
$353 million for the third quarter of 2012. 
The decrease in adjusted net earnings for the year ended December 31,
2012 from the year ended December 31, 2011 was primarily due to: 
- lower crude oil and NGLs and natural gas netbacks; 
- lower realized synthetic crude oil ("SCO") prices; 
- higher depletion, depreciation and amortization expense; and 
- higher realized risk management losses; 
partially offset by: 
- higher crude oil and SCO sales volumes in the North America and Oil
Sands Mining and Upgrading segments. 
The decrease in adjusted net earnings for the fourth quarter of 2012
from the fourth quarter of 2011 was primarily due to: 
- lower crude oil and NGLs and natural gas netbacks; 
- lower realized SCO prices; 
- lower natural gas sales volumes; 
- lower SCO sales volumes in the Oil Sands Mining and Upgrading
segment; 
- higher depletion, depreciation and amortization expense; and 
- the impact of a stronger Canadian dollar; 
partially offset by: 
- higher crude oil sales volumes in the North America segment. 
The adjusted net earnings for the fourth quarter of 2012 were
comparable with the third quarter of 2012. 
The impacts of share-based compensation, risk management activities
and changes in foreign exchange rates are expected to continue to
contribute to quarterly volatility in consolidated net earnings and
are discussed in detail in the relevant sections of this MD&A. 
Cash flow from operations for the year ended December 31, 2012 was
$6,013 million compared with $6,547 million for the year ended
December 31, 2011. Cash flow from operations for the fourth quarter
of 2012 was $1,548 million compared with $2,158 million for the
fourth quarter of 2011 and $1,431 million for the third quarter of
2012. The fluctuations in cash flow from operations from the
comparable periods was primarily due to the factors noted above
relating to the 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 year ended December 31,
2012 increased 9% to 654,665 BOE/d from 598,526 BOE/d for the year
ended December 31, 2011. Total production before royalties for the
fourth quarter of 2012 was comparable with the fourth quarter of 2011
and the third quarter of 2012. 
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       Dec 31     Sep 30     Jun 30     Mar 31
 share amounts)                        2012       2012       2012       2012
----------------------------------------------------------------------------
Product sales                    $    4,059 $    3,978 $    4,187 $    3,971
Net earnings                     $      352 $      360 $      753 $      427
Net earnings per common share
  - basic                        $     0.32 $     0.33 $     0.68 $     0.39
  - diluted                      $     0.32 $     0.33 $     0.68 $     0.39
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
($ millions, except per common       Dec 31     Sep 30     Jun 30     Mar 31
 share amounts)                        2011       2011       2011       2011
----------------------------------------------------------------------------
Product sales                    $    4,788 $    3,690 $    3,727 $    3,302
Net earnings                     $      832 $      836 $      929 $       46
Net earnings per common share
  - basic                        $     0.76 $     0.76 $     0.85 $     0.04
  - diluted                      $     0.76 $     0.76 $     0.84 $     0.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Volatility in the quarterly net earnings over the eight most recently
completed quarters was primarily due to: 
- Crude oil pricing - The impact of fluctuating demand, inventory
storage levels and geopolitical uncertainties on worldwide benchmark
pricing, the impact of the WCS Heavy Differential from West Texas
Intermediate ("WTI") in North America and the impact of the
differential between WTI and Dated Brent benchmark pricing in the
North Sea and Offshore Africa. 
- Natural gas pricing - The impact of fluctuations in both the demand
for natural gas and inventory storage levels, and the impact of
increased shale gas production in the US. 
- Crude oil and NGLs sales volumes - Fluctuations in production due
to the cyclic nature of the Company's Primrose thermal projects, the
results from the Pelican Lake water and polymer flood projects, the
record heavy oil drilling program, and the impact of the suspension
and recommencement of production at Horizon. Sales volumes also
reflected fluctuations due to timing of liftings and maintenance
activities in the North Sea and Offshore Africa, and payout of the
Baobab field in May 2011. 
- Natural gas sales volumes - Fluctuations in production due to the
Company's strategic decision to reduce natural gas drilling activity
in North America and the allocation of capital to higher return crude
oil projects, as well as natural decline rates, shut-in natural gas
production due to pricing and the impact and timing of acquisitions. 
- Production expense - Fluctuations primarily due to the impact of
the demand for services, fluctuations in product mix, the impact of
seasonal costs 
that are dependent on weather, production and cost
optimizations in North America, acquisitions of natural gas producing
properties in 2011 that had higher operating costs per Mcf than the
Company's existing properties, and the suspension and recommencement
of production at Horizon. 
- Depletion, depreciation and amortization - Fluctuations due to
changes in sales volumes, proved reserves, asset retirement
obligations, finding and development costs associated with crude oil
and natural gas exploration, estimated future costs to develop the
Company's proved undeveloped reserves, and the impact of the
suspension and 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
recorded with respect to US dollar denominated debt, partially offset
by the impact of cross currency swap hedges. 
- Income tax expense - Fluctuations in income tax expense include
statutory tax rate and other legislative changes substantively
enacted in the various periods. 
BUSINESS ENVIRONMENT 


 
                             Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
                            2012       2012       2011       2012       2011
----------------------------------------------------------------------------
WTI benchmark price
 (US$/bbl)            $    88.20 $    92.19 $    94.02 $    94.19 $    95.14
Dated Brent benchmark
 price (US$/bbl)      $   110.03 $   109.57 $   109.29 $   111.56 $   111.29
WCS blend
 differential from
 WTI (US$/bbl)        $    18.15 $    21.78 $    10.49 $    21.05 $    17.10
WCS blend
 differential from
 WTI (%)                     21%        24%        11%        22%        18%
SCO price (US$/bbl)   $    91.90 $    90.84 $   102.95 $    92.59 $   103.63
Condensate benchmark
 price (US$/bbl)      $    98.13 $    96.09 $   108.68 $   100.92 $   105.38
NYMEX benchmark price
 (US$/MMBtu)          $     3.36 $     2.82 $     3.61 $     2.80 $     4.07
AECO benchmark price
 (C$/GJ)              $     2.89 $     2.08 $     3.29 $     2.28 $     3.48
US/Canadian dollar
 average exchange
 rate (US$)           $   1.0088 $   1.0047 $   0.9773 $   1.0004 $   1.0111
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Commodity Prices 
Crude oil sales contracts in the North America segment are typically
based on WTI benchmark pricing. WTI averaged US$94.19 per bbl for the
year ended December 31, 2012, a decrease of 1% from US$95.14 per bbl
for the year ended December 31, 2011. WTI averaged US$88.20 per bbl
for the fourth quarter of 2012, a decrease of 6% from US$94.02 per
bbl for the fourth quarter of 2011, and a decrease of 4% from
US$92.19 per bbl for the third quarter of 2012. WTI pricing was
reflective of the political instability in the Middle East, the
declining optimism in the United States economy related to the fiscal
cliff, the European debt crisis, and lower than expected growth in
Asian demand. 
Crude oil sales contracts for the Company's North Sea and Offshore
Africa segments are typically based on Dated Brent ("Brent") pricing,
which is representative of international markets and overall world
supply and demand. Brent averaged US$111.56 per bbl for the year
ended December 31, 2012 and was comparable with the year ended
December 31, 2011. Brent averaged US$110.03 per bbl for the fourth
quarter of 2012 and was comparable with the comparative periods. The
higher Brent pricing relative to WTI was due to logistical
constraints and high inventory levels of crude oil at Cushing. 
The WCS Heavy Differential averaged 22% for the year ended December
31, 2012 compared with 18% for the year ended December 31, 2011. The
WCS Heavy Differential averaged 21% for the fourth quarter of 2012,
compared with 11% in the fourth quarter of 2011, and 24% for the
third quarter of 2012. The WCS Heavy Differential for October and
November 2012 narrowed, averaging 11% and 16% respectively. The WCS
Heavy Differential widened in December 2012 to average 34% as a
result of unplanned Enbridge pipeline capacity limitations and
refinery plans to lower crude inventories for year end. The impact of
higher WCS Heavy Differentials in January and February 2013 of 35%
and 39% respectively were partially offset by higher overall WTI
benchmark pricing. The WCS Heavy Differential narrowed in March 2013
to average approximately 29%. 
The Company uses condensate as a blending diluent for heavy crude oil
pipeline shipments. During the fourth quarter of 2012, condensate
prices continued to trade at a premium to WTI, similar to prior
periods, reflecting normal seasonality. 
The Company anticipates continued volatility in crude oil pricing
benchmarks due to supply and demand factors, geopolitical events, and
the timing and extent of the economic recovery. The WCS Heavy
Differential is expected to continue to reflect seasonal demand
fluctuations, changes in transportation logistics, and refinery
utilization and shutdowns. 
NYMEX natural gas prices averaged US$2.80 per MMBtu for the year
ended December 31, 2012, a decrease of 31% from US$4.07 per MMBtu for
the year ended December 31, 2011. NYMEX natural gas prices averaged
US$3.36 per MMBtu for the fourth quarter of 2012, a decrease of 7%
from US$3.61 per MMBtu for the fourth quarter of 2011, and an
increase of 19% from US$2.82 per MMBtu for the third quarter of 2012. 
AECO natural gas prices for the year ended December 31, 2012 averaged
$2.28 per GJ, a decrease of 34% from $3.48 per GJ for the year ended
December 31, 2011. AECO natural gas prices for the fourth quarter of
2012 averaged $2.89 per GJ, a decrease of 12% from $3.29 per GJ for
the fourth quarter of 2011, and an increase of 39% from $2.08 per GJ
for the third quarter of 2012. 
During the fourth quarter of 2012, natural gas prices continued to
recover from the low pricing levels in 2012. While Canadian
production has declined in response to low prices, US production has
held steady during 2012. Natural gas pricing continues to be volatile
as the market still requires a shift to higher utilization of gas
fired electric generation to offset the strong North America supply
position. 
The Company continues to focus on its crude oil marketing strategy
including a blending strategy that expands markets within current
pipeline infrastructure, supporting pipeline projects that provide
crude oil transportation to new markets, and supporting incremental
heavy crude oil conversion capacity. During the fourth quarter of
2012, the Company entered into a 20 year transportation agreement to
ship 75,000 bbl/d of crude oil on the proposed Kinder Morgan Trans
Mountain Expansion from Edmonton, Alberta to Vancouver, British
Columbia. The regulatory approval process will begin in 2013 with a
planned in-service date in 2017. 
DAILY PRODUCTION, before royalties 


 
                                Three Months Ended           Year Ended
                          --------------------------------------------------
                             Dec 31    Sep 30    Dec 31    Dec 31    Dec 31
                               2012      2012      2011      2012      2011
-----------------------------------------------------
-----------------------
Crude oil and NGLs (bbl/d)
North America -
 Exploration and
 Production                 351,983   332,895   291,839   326,829   295,618
North America -Oil Sands
 Mining and Upgrading        83,079    99,205   102,952    86,077    40,434
North Sea                    19,140    19,502    26,769    19,824    29,992
Offshore Africa              15,762    17,566    22,726    18,648    23,009
----------------------------------------------------------------------------
                            469,964   469,168   444,286   451,378   389,053
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America                 1,113     1,169     1,255     1,198     1,231
North Sea                         1         2         6         2         7
Offshore Africa                  20        20        19        20        19
----------------------------------------------------------------------------
                              1,134     1,191     1,280     1,220     1,257
----------------------------------------------------------------------------
Total barrels of oil
 equivalent (BOE/d)         658,973   667,616   657,599   654,665   598,526
----------------------------------------------------------------------------
Product mix
Light and medium crude oil
 and NGLs                        15%       15%       17%       16%       18%
Pelican Lake heavy crude
 oil                              5%        6%        6%        6%        6%
Primary heavy crude oil          20%       19%       17%       19%       18%
Bitumen (thermal oil)            18%       15%       12%       15%       16%
Synthetic crude oil              13%       15%       16%       13%        7%
Natural gas                      29%       30%       32%       31%       35%
----------------------------------------------------------------------------
Percentage of product
 sales (1)(excluding
 midstream revenue)
Crude oil and NGLs               89%       92%       90%       91%       86%
Natural gas                      11%        8%       10%        9%       14%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
                                    Three Months Ended        Year Ended
                               ---------------------------------------------
                                  Dec 31   Sep 30   Dec 31   Dec 31   Dec 31
                                    2012     2012     2011     2012     2011
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America - Exploration and
 Production                      305,577  261,655  230,522  273,374  240,006
North America - Oil Sands
 Mining and Upgrading             79,691   95,704   98,287   82,171   38,721
North Sea                         19,096   19,441   26,714   19,772   29,919
Offshore Africa                   10,358   11,662   19,331   13,628   20,532
----------------------------------------------------------------------------
                                 414,722  388,462  374,854  388,945  329,178
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America                      1,047    1,159    1,211    1,171    1,186
North Sea                              1        2        6        2        7
Offshore Africa                       16       16       16       17       16
----------------------------------------------------------------------------
                                   1,064    1,177    1,233    1,190    1,209
----------------------------------------------------------------------------
Total barrels of oil equivalent
 (BOE/d)                         592,080  584,577  580,242  587,246  530,576
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
The Company's business approach is to maintain large project
inventories and production diversification among each of the
commodities it produces; namely natural gas, light and medium crude
oil and NGLs, Pelican Lake heavy crude oil, primary heavy crude oil,
bitumen (thermal oil) and SCO. 
Crude oil and NGLs production for the year ended December 31, 2012
increased 16% to 451,378 bbl/d from 389,053 bbl/d for the year ended
December 31, 2011. Crude oil and NGLs production for the fourth
quarter of 2012 increased 6% to 469,964 bbl/d from 444,286 bbl/d for
the fourth quarter of 2011 and was comparable with the third quarter
of 2012. The increase in production from the comparable periods in
2011 was primarily related to the impact of a strong heavy crude oil
drilling program and the cyclic nature of the Company's thermal
operations. Crude oil and NGLs production in the fourth quarter of
2012 was within the Company's previously issued guidance of 467,000
to 495,000 bbl/d. 
Natural gas production for the year ended December 31, 2012 decreased
3% to 1,220 MMcf/d from 1,257 MMcf/d for the year ended December 31,
2011. Natural gas production for the fourth quarter of 2012 decreased
11% to 1,134 MMcf/d from 1,280 MMcf/d for the fourth quarter of 2011
and decreased 5% from 1,191 MMcf/d for the third quarter of 2012. The
decrease in natural gas production for the three months and year
ended December 31, 2012 from the comparable periods was primarily a
result of a strategic reduction of natural gas drilling as the
Company allocated capital to higher return crude oil projects, as
well as expected production declines. During the fourth quarter of
2012, certain gas processing contract arrangements were ended to
provide greater flexibility of cost control, resulting in the shut in
of additional natural gas production. As a result of the shut-in
natural gas, natural gas production in the fourth quarter of 2012 was
slightly below the Company's previously issued guidance of 1,145 to
1,165 MMcf/d. 
For 2013, annual production guidance is targeted to average between
482,000 and 513,000 bbl/d of crude oil and NGLs and between 1,085 and
1,145 MMcf/d of natural gas. First quarter 2013 production guidance
is targeted to average between 471,000 and 495,000 bbl/d of crude oil
and NGLs and between 1,130 and 1,150 MMcf/d of natural gas. 
North America - Exploration and Production 
North America crude oil and NGLs production for the year ended
December 31, 2012 increased 11% to average 326,829 bbl/d from 295,618
bbl/d for the year ended December 31, 2011. For the fourth quarter of
2012, crude oil and NGLs production increased 21% to average 351,983
bbl/d compared with 291,839 bbl/d for the fourth quarter of 2011 and
increased 6% from 332,895 bbl/d in the third quarter of 2012.
Increases in crude oil and NGLs production from comparable periods
were primarily due to the impact of a strong heavy crude oil drilling
program and the cyclic nature of the Company's thermal operations.
Fourth quarter 2012 production of crude oil and NGLs was within the
Company's previously issued guidance of 350,000 bbl/d to 365,000
bbl/d. First quarter 2013 production guidance is targeted to average
between 335,000 and 349,000 bbl/d for crude oil and NGLs. 
Natural gas production for the year ended December 31, 2012 decreased
3% to 1,198 MMcf/d compared with 1,231 MMcf/d for the year ended
December 31, 2011. Natural gas production decreased 11% to 1,113
MMcf/d for the fourth quarter of 2012 compared with 1,255 MMcf/d in
the fourth quarter of 2011 and decreased 5% from 1,169 MMcf/d in the
third quarter of 2012. The decrease in natural gas production for the
three months and year ended December 31, 2012 from the comparable
periods was primarily a result of a strategic reduction of natural
gas drilling as the Company allocated capital to higher return crude
oil projects, as w
ell as expected production declines. During the
fourth quarter of 2012, certain gas processing contract arrangements
were ended to provide greater flexibility of cost control, resulting
in the shut in of additional natural gas production. 
North America - Oil Sands Mining and Upgrading 
Production averaged 86,077 bbl/d for the year ended December 31, 2012
compared with 40,434 bbl/d for the year ended December 31, 2011. For
the fourth quarter of 2012, SCO production averaged 83,079 bbl/d
compared with 102,952 bbl/d for the fourth quarter of 2011 and 99,205
bbl/d for the third quarter of 2012. Production for the year ended
December 31, 2012 increased from the comparable period in 2011 as a
result of the suspension of production during a portion of 2011.
Fourth quarter production in 2012 decreased from the fourth quarter
of 2011 and the third quarter of 2012 as the Company completed a 12
day planned maintenance outage in October 2012 as well as additional
maintenance in the ore preparation plants in December 2012.
Production of SCO was slightly below the Company's previously issued
guidance of 85,000 to 92,000 bbl/d for the fourth quarter of 2012.
First quarter 2013 production guidance is targeted to average between
105,000 and 111,000 bbl/d. 
North Sea 
North Sea crude oil production for the year ended December 31, 2012
decreased 34% to 19,824 bbl/d from 29,992 bbl/d for the year ended
December 31, 2011. For the fourth quarter of 2012, North Sea crude
oil production decreased 28% to 19,140 bbl/d from 26,769 bbl/d for
the fourth quarter of 2011, and decreased 2% from 19,502 bbl/d in the
third quarter of 2012. The decrease in production volumes for the
three months and year ended December 31, 2012 from the comparable
periods was primarily due to temporary shut ins of the third-party
operated pipeline to Sullom Voe, which caused all Ninian and
associated fields to be shut in for a portion of the third and fourth
quarters of 2012, the suspension of production at Banff/Kyle, and
natural field declines. In addition, the Company accelerated its
fourth quarter 2012 planned turnaround activity to mitigate the
impact of the pipeline outage. 
In December 2011, the Banff Floating Production, Storage and
Offloading Vessel ("FPSO") and subsea infrastructure suffered storm
damage. Operations at Banff/Kyle, with combined net production of
approximately 3,500 bbl/d, were suspended. The FPSO and associated
floating storage unit have subsequently been removed from the field
and the FPSO is currently in dry dock for assessment of damages and
repair timeframe. The extent of the property damage, including
associated costs, is not expected to be significant. 
Offshore Africa 
Offshore Africa crude oil production decreased 19% to 18,648 bbl/d
for the year ended December 31, 2012 from 23,009 bbl/d for the year
ended December 31, 2011. Fourth quarter 2012 crude oil production
averaged 15,762 bbl/d, decreasing 31% from 22,726 bbl/d for the
fourth quarter of 2011 and decreasing 10% from 17,566 bbl/d in the
third quarter of 2012. The decrease in production volumes for the
three months and year ended December 31, 2012 from the comparable
periods was due to natural field declines, planned turnaround
activity at Espoir, and the shut in of approximately 1,500 bbl/d of
production at the Olowi field, Gabon. The Company currently has a
vessel on-site in Gabon assessing the operability of the midwater
arch. 
International Guidance 
The Company's North Sea and Offshore Africa fourth quarter 2012 crude
oil and NGLs production was within the Company's previously issued
guidance of 32,000 to 38,000 bbl/d. First quarter 2013 production
guidance is targeted to average between 31,000 and 35,000 bbl/d of
crude oil. 
Crude Oil Inventory Volumes 
The Company recognizes revenue on its crude oil production when title
transfers to the customer and delivery has taken place. Revenue has
not been recognized on crude oil volumes that were stored in various
tanks, pipelines, or floating production, storage and offloading
vessels, as follows: 


 
                                              ------------------------------
                                                  Dec 31    Sep 30    Dec 31
(bbl)                                               2012      2012      2011
----------------------------------------------------------------------------
North America - Exploration and Production       643,758   656,340   557,475
North America - Oil Sands Mining and Upgrading
 (SCO)                                           993,627   888,442 1,021,236
North Sea                                         77,018   150,269   286,633
Offshore Africa                                1,036,509 1,058,992   527,312
----------------------------------------------------------------------------
                                               2,750,912 2,754,043 2,392,656
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION 


 
                             Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
                            2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Crude oil and NGLs
 ($/bbl) (1)
Sales price (2)       $    64.23 $    67.59 $    85.28 $    70.24 $    77.46
Royalties                   8.59      12.08      15.53      10.67      12.30
Production expense         15.32      15.79      16.85      16.11      15.75
----------------------------------------------------------------------------
Netback               $    40.32 $    39.72 $    52.90 $    43.46 $    49.41
----------------------------------------------------------------------------
Natural gas ($/Mcf)
 (1)
Sales price (2)       $     3.16 $     2.28 $     3.50 $     2.44 $     3.73
Royalties                   0.21       0.05       0.18       0.09       0.18
Production expense          1.43       1.30       1.15       1.31       1.15
----------------------------------------------------------------------------
Netback               $     1.52 $     0.93 $     2.17 $     1.04 $     2.40
----------------------------------------------------------------------------
Barrels of oil
 equivalent ($/BOE)
 (1)
Sales price (2)       $    49.83 $    49.08 $    61.21 $    50.81 $    57.16
Royalties                   6.22       7.94      10.14       7.07       8.12
Production expense         13.11      12.97      13.12      13.14      12.42
----------------------------------------------------------------------------
Netback               $    30.50 $    28.17 $    37.95 $    30.60 $    36.62
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
                             Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
                            2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Crude oil and NGLs
 ($/bbl) (1)(2)
North America         $    60.17 $    63.73 $    81.02 $    65.54 $    72.17
North Sea             $   108.82 $   106.68 $   109.71 $   110.75 $   108.56
Offshore Africa       $    97.97 $   112.59 $   102.74 $   111.18 $   105.53
Company average       $    64.23 $    67.59 $    85.28 $    70.24 $    77.46
 
Natural gas ($/Mcf)
 (1)(2)
North America         $     3.03 
$     2.15 $     3.36 $     2.31 $     3.64
North Sea             $     2.67 $     3.65 $     4.17 $     3.70 $     4.07
Offshore Africa       $    10.25 $     9.95 $    12.79 $    10.17 $     9.56
Company average       $     3.16 $     2.28 $     3.50 $     2.44 $     3.73
 
Company average
 ($/BOE) (1)(2)       $    49.83 $    49.08 $    61.21 $    50.81 $    57.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
(2) Net of transportation and blending costs and excluding risk
management activities. 
North America 
North America realized crude oil prices decreased 9% to average
$65.54 per bbl for the year ended December 31, 2012 from $72.17 per
bbl for the year ended December 31, 2011. North America realized
crude oil prices averaged $60.17 per bbl for the fourth quarter of
2012, a decrease of 26% compared with $81.02 per bbl for the fourth
quarter of 2011 and a decrease of 6% compared with $63.73 per bbl for
the third quarter of 2012. The decrease in prices for the three
months and year ended December 31, 2012 from the comparable periods
in 2011 was primarily a result of the lower WTI benchmark pricing,
the widening of the WCS Heavy Differential and the fluctuations in
the Canadian dollar relative to the US dollar. The decrease in prices
for the fourth quarter of 2012 from the third quarter of 2012 was
primarily due to the lower WTI benchmark pricing, partially offset by
the narrowing of the WCS Heavy Differential. The Company continues to
focus on its crude oil blending marketing strategy and in the fourth
quarter of 2012 contributed approximately 165,000 bbl/d of heavy
crude oil blends to the WCS stream. 
North America realized natural gas prices decreased 37% to average
$2.31 per Mcf for the year ended December 31, 2012 from $3.64 per Mcf
for the year ended December 31, 2011. North America realized natural
gas prices decreased 10% to average $3.03 per Mcf for the fourth
quarter of 2012 compared with $3.36 per Mcf in the fourth quarter of
2011, and increased 41% compared with $2.15 per Mcf for the third
quarter of 2012. The decrease in natural gas prices for the three
months and year ended December 31, 2012 from the comparable periods
in 2011 was primarily due to lower NYMEX and AECO benchmark pricing
related to the impact of strong supply from US shale projects. The
increase in natural gas prices for the fourth quarter of 2012 from
the third quarter of 2012 was primarily due to higher NYMEX and AECO
benchmark pricing related to a shift to higher utilization of gas
fired electric generation and seasonality. 
Comparisons of the prices received in North America Exploration and
Production by product type were as follows: 


 
                                           ---------------------------------
                                                Dec 31     Sep 30     Dec 31
(Quarterly Average)                               2012       2012       2011
----------------------------------------------------------------------------
Wellhead Price(1) (2)
Light and medium crude oil and NGLs ($/bbl) $    68.67 $    67.33 $    86.05
Pelican Lake heavy crude oil ($/bbl)        $    61.32 $    63.03 $    81.64
Primary heavy crude oil ($/bbl)             $    59.42 $    61.54 $    79.91
Bitumen (thermal oil) ($/bbl)               $    56.14 $    64.56 $    78.38
Natural gas ($/Mcf)                         $     3.03 $     2.15 $     3.36
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
(2) Net of transportation and blending costs and excluding risk
management activities. 
North Sea 
North Sea realized crude oil prices increased 2% to average $110.75
per bbl for the year ended December 31, 2012 from $108.56 per bbl for
the year ended December 31, 2011. Realized crude oil prices averaged
$108.82 per bbl for the fourth quarter of 2012, a decrease of 1% from
$109.71 per bbl for the fourth quarter of 2011, and an increase of 2%
from $106.68 per bbl for the third quarter of 2012. The fluctuations
in realized crude oil prices in the North Sea from the comparable
periods in 2011 were primarily the result of fluctuations in the
Brent benchmark pricing and the Canadian dollar, and the timing of
liftings. 
Offshore Africa 
Offshore Africa realized crude oil prices increased 5% to average
$111.18 per bbl for the year ended December 31, 2012 from $105.53 per
bbl for the year ended December 31, 2011. Realized crude oil prices
decreased 5% to average $97.97 per bbl for the fourth quarter of 2012
from $102.74 per bbl for the fourth quarter of 2011, and decreased
13% from $112.59 per bbl for the third quarter of 2012. The
fluctuations in realized crude oil prices in Offshore Africa from the
comparable periods were primarily the result of the fluctuations in
the Brent benchmark pricing and the Canadian dollar, and the timing
of liftings. 
ROYALTIES - EXPLORATION AND PRODUCTION 


 
                             Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
                            2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Crude oil and NGLs
 ($/bbl) (1)
North America         $     7.93 $    11.65 $    17.10 $    10.33 $    13.51
North Sea             $     0.25 $     0.33 $     0.23 $     0.29 $     0.26
Offshore Africa       $    33.59 $    37.84 $    15.35 $    29.46 $    12.47
Company average       $     8.59 $    12.08 $    15.53 $    10.67 $    12.30
 
Natural gas ($/Mcf)
 (1)
North America         $     0.18 $     0.02 $     0.15 $     0.06 $     0.16
Offshore Africa       $     1.74 $     1.89 $     2.33 $     1.77 $     1.59
Company average       $     0.21 $     0.05 $     0.18 $     0.09 $     0.18
 
Company average
 ($/BOE) (1)          $     6.22 $     7.94 $    10.14 $     7.07 $     8.12
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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 year ended
December 31, 2012 compared with the year ended December 31, 2011
reflected benchmark commodity prices and the widening of the WCS
Heavy Differential. 
Crude oil and NGLs royalties averaged approximately 16% of product
sales in 2012 compared with 19% in 2011. Crude oil and NGLs royalties
averaged approximately 13% of product sales for the fourth quarter of
2012 compared with 21% for the fourth quarter of 2011 and 18% for the
third quarter of 2012. The decrease in royalties from the comparable
periods was the result of lower WTI benchmark pricing and changes in
the WCS Heavy Differential. Crude oil and NGLs royalties per bbl are
anticipated to average 16% to 18% of product sales for 2013. 
Natural gas royalties averaged approximately 3% of product sales in
2012 compared with 4% in 2011. Natural gas royalties averaged
approximately 6% of product sales for the fourth quarter of 2012
compared with 4% for the fourth quarter of 2011 and 1% for the third
quarter of 2012. The fluctuations in natural gas royalty rates from
the comparable periods were primarily the result of fluctuations in
realized natural gas prices, together with gas cost allowance
adjustments. Natural gas royalties are anticipated to average 4% to
6% of product sales for 2013. 
Offshore Africa 
Under the terms of the various Production Sharing Contracts, royalty
rates fluctuate based on realized commodity pricing, capital and
operating costs, the status o
f payouts, and the timing of liftings
from each field. 
Royalty rates as a percentage of product sales averaged approximately
26% in 2012 compared with 17% in 2011. Royalty rates as a percentage
of product sales averaged approximately 32% for the fourth and third
quarters of 2012 compared with 18% for the fourth quarter of 2011.
The increase in royalty rates from the comparable periods in 2011 was
due to higher crude oil prices during the year, adjustments to
royalties on liftings, and the payout of the Baobab field in May
2011. 
Offshore Africa royalty rates are anticipated to average 9% to 11% of
product sales for 2013. 
PRODUCTION EXPENSE - EXPLORATION AND PRODUCTION 


 
                             Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
                            2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Crude oil and NGLs
 ($/bbl) (1)
North America         $    12.79 $    12.52 $    14.32 $    13.40 $    13.21
North Sea             $    54.41 $    60.94 $    36.45 $    53.53 $    37.06
Offshore Africa       $    22.14 $    38.34 $    22.16 $    23.11 $    20.72
Company average       $    15.32 $    15.79 $    16.85 $    16.11 $    15.75
 
Natural gas ($/Mcf)
 (1)
North America         $     1.40 $     1.28 $     1.12 $     1.28 $     1.12
North Sea             $     3.58 $     3.44 $     3.51 $     3.75 $     2.83
Offshore Africa       $     3.19 $     2.37 $     2.52 $     2.27 $     2.03
Company average       $     1.43 $     1.30 $     1.15 $     1.31 $     1.15
 
Company average
 ($/BOE) (1)          $    13.11 $    12.97 $    13.12 $    13.14 $    12.42
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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 year
ended December 31, 2012 averaged $13.40 per bbl and was comparable
with the year ended December 31, 2011. North America crude oil and
NGLs production expense for the fourth quarter of 2012 decreased 11%
to $12.79 per bbl from $14.32 per bbl for the fourth quarter of 2011
and increased 2% from $12.52 per bbl for the third quarter of 2012.
The increase in production expense for the three months ended
December 31, 2012 from the third quarter of 2012 was primarily the
result of higher servicing cost pressures in Heavy Oil. North America
2012 crude oil and NGLs production expense was slightly higher than
the Company's previously issued guidance of $12.75 to $13.25 per bbl,
and is anticipated to average $12.00 to $14.00 per bbl for 2013. 
North America natural gas production expense for the year ended
December 31, 2012 increased 14% to $1.28 per Mcf from $1.12 per Mcf
for the year ended December 31, 2011. North America natural gas
production expense for the fourth quarter of 2012 increased 25% to
$1.40 per Mcf from $1.12 per Mcf for the fourth quarter of 2011 and
increased 9% from $1.28 per Mcf for the third quarter of 2012.
Natural gas production expense for the three months and year ended
December 31, 2012 increased from the comparable periods due to the
impact of shut-in production and lower production volumes related to
the curtailment of capital expenditures related to natural gas
activity. During the fourth quarter of 2012, certain gas processing
contract arrangements were ended to provide greater flexibility of
cost control, resulting in the shut in of additional natural gas
production. North America 2012 natural gas production expense was
slightly higher than the Company's previously issued guidance of
$1.22 to $1.26 per Mcf, and is anticipated to average $1.30 to $1.40
per Mcf for 2013. 
North Sea 
North Sea crude oil production expense for the year ended December
31, 2012 increased 44% to $53.53 per bbl from $37.06 per bbl for the
year ended December 31, 2011. North Sea crude oil production expense
for the fourth quarter of 2012 decreased 11% to $54.41 per bbl from
$60.94 per bbl for the third quarter of 2012 and increased 49% from
$36.45 per bbl for the fourth quarter of 2011. Production expense
decreased for the fourth quarter of 2012 from the third quarter of
2012 due to a reduced level of maintenance activity. Production
expense increased on a per barrel basis for the three months and year
ended December 31, 2012 from the comparable periods in 2011 due to
the impact of production declines on relatively fixed costs,
temporary shut ins of the third-party operated pipeline to Sullom
Voe, and higher maintenance costs related to turnaround activity.
North Sea 2012 crude oil production expense was slightly higher than
the Company's previously issued guidance of $52.00 to $53.00 per bbl,
and is anticipated to average $62.00 to $66.00 per bbl for 2013 due
to natural declines on a relatively fixed cost structure. 
Offshore Africa 
Offshore Africa crude oil production expense increased 12% to $23.11
per bbl from $20.72 per bbl for the year ended December 31, 2012.
Offshore Africa crude oil production expense for the fourth quarter
of 2012 averaged $22.14 per bbl, comparable with the fourth quarter
of 2011, and decreased 42% from $38.34 per bbl for the third quarter
of 2012. Production expense for the three months and year ended
December 31, 2012 fluctuated from the comparable periods as a result
of the timing of liftings from various fields, which have different
cost structures. Offshore Africa 2012 crude oil production expense
was below the Company's previously issued guidance of $24.50 to
$25.50 per bbl, and is anticipated to average $33.50 to $37.50 per
bbl for 2013 due to timing of liftings from various fields. 
DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND PRODUCTION 


 
                              Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
                            2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Expense ($ millions)  $    1,097 $      931 $      863 $    3,874 $    3,331
  $/BOE (1)           $    20.66 $    18.00 $    16.51 $    18.65 $    16.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
Depletion, depreciation and amortization expense increased for the
three months and year ended December 30, 2012 compared with 2011 due
to higher sales volumes in North America associated with heavy oil
drilling and higher overall future development costs. The increase in
depletion, depreciation and amortization expense from the third
quarter of 2012 was primarily due to higher sales volumes in North
America. 
ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND PRODUCTION 


 
                              Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
                            2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Expense ($ millions)  $       30 $       30 $       28 $      119 $      110
  $/BOE (1)           $     0.56 $     0.59 $     0.54 $     0.57 $     0.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
Asset retirement ob
ligation 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 October 2012, the Company completed a planned 12 day
maintenance outage, as well as additional maintenance in the ore
preparation plants during December 2012. These maintenance activities
resulted in production of 83,079 bbl/d of SCO in the fourth quarter
of 2012, which was slightly below the Company's previously issued
guidance of 85,000 to 92,000 bbl/d of SCO. The Company continues to
focus on efficient and effective operations at Horizon and place
emphasis on safe, steady, reliable operations, resulting in January
and February 2013 production of approximately 113,000 bbl/d and
107,000 bbl/d respectively. In the second quarter of 2013, Horizon
will enter into a 24 day planned maintenance turnaround, resulting in
a plant-wide shut down. The impact of the turnaround has been
reflected in the Company's 2013 production, cash production cost and
capital expenditure guidance. 
PRODUCT PRICES AND ROYALTIES - OIL SANDS MINING AND UPGRADING 


 
                             Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
($/bbl) (1)                 2012       2012       2011       2012       2011
----------------------------------------------------------------------------
SCO sales price (2)   $    87.34 $    87.40 $   103.16 $    88.91 $    99.74
Bitumen value for
 royalty purposes (3) $    58.12 $    57.40 $    69.91 $    59.93 $    61.86
Bitumen royalties (4) $     3.80 $     3.45 $     4.21 $     4.34 $     3.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes
excluding the period during suspension of production. 
(2) Net of transportation. 
(3) Calculated as the simple quarterly average of the bitumen
valuation methodology price. 
(4) Calculated based on actual bitumen royalties expensed during the
period; divided by the corresponding SCO sales volumes. 
Realized SCO sales prices averaged $88.91 per bbl for the year ended
December 31, 2012, a decrease of 11% compared with $99.74 per bbl for
the year ended December 31, 2011. Realized SCO sales prices averaged
$87.34 per bbl for the fourth quarter of 2012, a decrease of 15%
compared with $103.16 per bbl for the fourth quarter of 2011 and were
comparable with the third quarter of 2012, reflecting benchmark
pricing and prevailing differentials. 
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              Year Ended
                   ---------------------------------------------------------
                        Dec 31     Sep 30     Dec 31     Dec 31      Dec 31
($ millions)              2012       2012       2011       2012        2011
----------------------------------------------------------------------------
Cash production
 costs              $      372 $      398 $      344 $    1,504  $    1,127
Less: costs
 incurred during
 the period of
 suspension of
 production                  -          -          -       (154)       (581)
----------------------------------------------------------------------------
Adjusted cash
 production costs   $      372 $      398 $      344 $    1,350  $      546
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Adjusted cash
 production costs,
 excluding natural
 gas costs          $      342 $      373 $      316 $    1,254  $      502
Adjusted natural
 gas costs                  30         25         28         96          44
----------------------------------------------------------------------------
Adjusted cash
 production costs   $      372 $      398 $      344 $    1,350  $      546
----------------------------------------------------------------------------
----------------------------------------------------------------------------
                             Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
($/bbl) (1)                 2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Adjusted cash
 production costs,
 excluding natural
 gas costs            $    45.31 $    40.03 $    33.11 $    39.79 $    33.68
Adjusted natural gas
 costs                      3.96       2.66       2.93       3.04       2.96
----------------------------------------------------------------------------
Adjusted cash
 production costs     $    49.27 $    42.69 $    36.04 $    42.83 $    36.64
----------------------------------------------------------------------------
Sales (bbl/d)             81,936    101,263    103,710     86,153     40,847
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes
excluding the period during suspension of production. 
Adjusted cash production costs averaged $42.83 per bbl for the year
ended December 31, 2012, an increase of 17% compared with $36.64 per
bbl for the year ended December 31, 2011. Adjusted cash production
costs for the fourth quarter of 2012 averaged $49.27 per bbl, an
increase of 37% compared with $36.04 per bbl for the fourth quarter
of 2011 and an increase of 15% compared with $42.69 per bbl for the
third quarter of 2012, primarily due to the impact of lower
production volumes in the period. Cash production costs are
anticipated to average $38.00 to $41.00 per bbl for 2013. 
DEPLETION, DEPRECIATION AND AMORTIZATION - OIL SANDS MINING AND
UPGRADING 


 
                           Three Months Ended              Year Ended
                   ---------------------------------------------------------
                        Dec 31     Sep 30     Dec 31     Dec 31      Dec 31
($ millions)              2012       2012       2011       2012        2011
----------------------------------------------------------------------------
Depletion,
 depreciation and
 amortization       $      114 $      124 $      133 $      447  $      266
Less: depreciation
 incurred during
 the period of
 suspension of
 production                  -          -          -         (6)        (64)
----------------------------------------------------------------------------
Adjusted depletion,
 depreciation and
 amortization       $      114 $      124 $      133 $      441  $      202
----------------------------------------------------------------------------
  $/bbl (1)         $    15.12 $    13.31 $    13.91 $    13.99  $    13.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
                              Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
 ($ millions)      
         2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Expense               $        8 $        8 $        5 $       32 $       20
  $/bbl (1)           $     1.06 $     0.85 $     0.52 $     1.01 $     1.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(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             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
($ millions)                2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Revenue               $       26 $       24 $       22 $       93 $       88
Production expense             8          7          7         29         26
----------------------------------------------------------------------------
Midstream cash flow           18         17         15         64         62
Depreciation                   2          1          2          7          7
Equity loss from
 jointly controlled
 entity                        3          1          -          9          -
----------------------------------------------------------------------------
Segment earnings
 before taxes         $       13 $       15 $       13 $       48 $       55
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Midstream operating results were consistent with the comparable
periods. 
In the first quarter of 2011, the Company announced that it had
entered into a partnership agreement with North West Upgrading Inc.
to move forward with detailed engineering regarding the construction
and operation of a bitumen upgrader and refinery ("the Project") near
Redwater, Alberta. In addition, the partnership has entered into
processing agreements that target to process bitumen for the Company
and the Alberta Petroleum Marketing Commission ("APMC"), an agent of
the Government of Alberta, under a 30 year fee-for-service tolling
agreement under the Bitumen Royalty In Kind initiative. In the fourth
quarter of 2012, the Project was sanctioned by the Board of Directors
of each partner of the North West Redwater Partnership ("Redwater"),
and the associated target toll amounts were accepted by Redwater, the
Company and the APMC. 
ADMINISTRATION EXPENSE 


 
                              Three Months Ended             Year Ended
                     -------------------------------------------------------
                          Dec 31     Sep 30     Dec 31     Dec 31     Dec 31
 ($ millions)               2012       2012       2011       2012       2011
----------------------------------------------------------------------------
Expense               $       64 $       64 $       47 $      270 $      235
  $/BOE (1)           $     1.07 $     1.05 $     0.76 $     1.13 $     1.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
Administration expense for the three months and year ended December
31, 2012 increased from the comparable periods in 2011 primarily due
to higher staffing related costs and general corporate costs. 
SHARE-BASED COMPENSATION 


 
                          Three Months Ended               Year Ended
                  ----------------------------------------------------------
                       Dec 31      Sep 30     Dec 31     Dec 31      Dec 31
($ millions)             2012        2012       2011       2012        2011
----------------------------------------------------------------------------
(Recovery) expense $      (41) $       49 $      207 $     (214) $     (102)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
The Company's stock option plan provides current employees with the
right to receive common shares or a direct cash payment in exchange
for stock options surrendered. 
The Company recorded a $214 million share-based compensation recovery
for the year ended December 31, 2012, primarily as a result of
remeasurement of the fair value of outstanding stock options at the
end of the period related to a decrease in the Company's share price,
partially offset by normal course graded vesting of stock options
granted in prior periods and the impact of vested stock options
exercised or surrendered during the period. For the year ended
December 31, 2012, a $12 million recovery was recognized in respect
of capitalized share-based compensation to Oil Sands Mining and
Upgrading (December 31, 2011 - $nil). 
For the year ended December 31, 2012, the Company paid $7 million for
stock options surrendered for cash settlement (December 31, 2011 -
$14 million). 
INTEREST AND OTHER FINANCING COSTS 


 
                         Three Months Ended                Year Ended
                ------------------------------------------------------------
($ millions,
 except per BOE      Dec 31      Sep 30      Dec 31         Dec 31   Dec 31
 amounts)              2012        2012        2011           2012     2011
----------------------------------------------------------------------------
Expense, gross   $      115  $      119  $      102  $      462  $      432
Less:
 capitalized
 interest                32          27          19          98          59
----------------------------------------------------------------------------
Expense, net     $       83  $       92  $       83  $      364  $      373
  $/BOE (1)      $     1.37  $     1.51  $     1.35  $     1.52  $     1.71
Average
 effective
 interest rate          4.8%        4.9%        4.7%        4.8%        4.7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts expressed on a per unit basis are based on sales volumes. 
Gross interest and other financing costs for the year ended December
31, 2012 increased from the comparable period in 2011 due to higher
variable interest rates and the impact of a weaker Canadian dollar on
US dollar denominated debt; partially offset by lower average debt
levels. Gross interest and other financing costs for the fourth
quarter of 2012 increased from the comparable period in 2011 due to
higher variable interest rates, partially offset by lower average
debt levels and the impact of a stronger Canadian dollar on US dollar
denominated debt. Gross interest and other financing costs were
comparable with the third quarter of 2012. Capitalized interest of
$98 million for the year ended December 31, 2012 was related to the
Horizon Phase 2/3 expansion and the Kirby Thermal Oil Sands Project
("Kirby Project"). 
RISK MANAGEMENT ACTIVITIES 
The Company utilizes various derivative financial instruments to
manage its commodity price, foreign currency and interest rate
exposures. These derivative financial instruments are not intended
for trading or speculative purposes. 


 
                         Three Months Ended                Year Ended
                ------------------------------------------------------------
                     Dec 31      Sep 30      Dec 31      Dec 31      Dec 31
($ millions)           2012        2012        2011        2012        2011
------------------------------------------------------------------------
----
Crude oil and
 NGLs financial
 instruments     $       19  $       18  $       27  $       65  $      117
Foreign currency
 contracts and
 interest rate
 swaps                  (27)        119          (7)         97         (16)
----------------------------------------------------------------------------
Realized (gain)
 loss            $       (8) $      137  $       20  $      162  $      101
----------------------------------------------------------------------------
 
Crude oil and
 NGLs financial
 instruments     $       29  $       58  $        5  $        3  $     (134)
Foreign currency
 contracts and
 interest rate
 swaps                  (21)        (24)         53         (45)          6
----------------------------------------------------------------------------
Unrealized loss
 (gain)          $        8  $       34  $       58  $      (42) $     (128)
----------------------------------------------------------------------------
Net loss (gain)  $        -  $      171  $       78  $      120  $      (27)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Complete details related to outstanding derivative financial
instruments at December 31, 2012 are disclosed in note 13 to the
Company's unaudited interim consolidated financial statements. 
The Company recorded a net unrealized gain of $42 million ($37
million after-tax) on its risk management activities for the year
ended December 31, 2012, including an unrealized loss of $8 million
($4 million after-tax) for the fourth quarter of 2012 (September 30,
2012 - unrealized loss of $34 million; $22 million after-tax;
December 31, 2011 - unrealized loss of $58 million; $50 million
after-tax). 
FOREIGN EXCHANGE 


 
                         Three Months Ended                Year Ended
                ------------------------------------------------------------
                     Dec 31      Sep 30      Dec 31      Dec 31      Dec 31
($ millions)           2012        2012        2011        2012        2011
----------------------------------------------------------------------------
Net realized
 (gain) loss     $     (196) $       21  $       11  $     (178) $     (214)
Net unrealized
 loss (gain) (1)        254        (136)       (117)        129         215
----------------------------------------------------------------------------
Net loss (gain)  $       58  $     (115) $     (106) $      (49) $        1
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Amounts are reported net of the hedging effect of cross currency
swaps. 
The net realized foreign exchange gain for the year ended December
31, 2012 was primarily due to the repayment of US$350 million of
5.45% unsecured notes and 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
year ended December 31, 2012 was primarily related to the reversal of
the life-to-date unrealized foreign exchange gain on the repayment of
US$350 million of 5.45% unsecured notes; partially offset by the
impact of the strengthening of the Canadian dollar with respect to
remaining US dollar debt. The net unrealized loss (gain) for each of
the periods presented included the impact of cross currency swaps
(three months ended December 31, 2012 - unrealized gain of $27
million, September 30, 2012 - unrealized loss of $85 million,
December 31, 2011 - unrealized loss of $43 million; year ended
December 31, 2012 - unrealized loss of $53 million, December 31, 2011
- unrealized gain of $42 million). The US/Canadian dollar exchange
rate ended the fourth quarter of 2012 at US$1.0051 (September 30,
2012 - US$1.0166; December 31, 2011 - US$0.9833). 
INCOME TAXES 


 
                         Three Months Ended                Year Ended
                ------------------------------------------------------------
($ millions,
 except income       Dec 31      Sep 30      Dec 31      Dec 31      Dec 31
 tax rates)            2012        2012        2011        2012        2011
----------------------------------------------------------------------------
North America
 (1)             $       68  $       61  $      119  $      366  $      315
North Sea                29          22          84         115         245
Offshore Africa          56          50          50         206         140
PRT (recovery)
 expense - North
 Sea                     31         (19)         39          44         135
Other taxes               5           -           7          16          25
----------------------------------------------------------------------------
Current income
 tax expense            189         114         299         747         860
----------------------------------------------------------------------------
Deferred income         (34)         23         157           -         412
 tax (recovery)
 expense
Deferred PRT
 (recovery)
 expense - North
 Sea                    (35)          6         (13)        (30)         (5)
----------------------------------------------------------------------------
Deferred income         (69)         29         144         (30)        407
 tax (recovery)
 expense
----------------------------------------------------------------------------
                        120         143         443         717       1,267
Income tax rate
 and other
 legislative
 changes                  -         (58)          -         (58)       (104)
----------------------------------------------------------------------------
                 $      120  $       85  $      443  $      659  $    1,163
----------------------------------------------------------------------------
Effective income
 tax rate on
 adjusted net
 earnings from
 operations (2)        25.5%       23.8%       30.1%       27.8%       27.7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Includes North America Exploration and Production, Midstream, and
Oil Sands Mining and Upgrading segments. 
(2) Excludes the impact of current and deferred PRT expense and other
current income tax expense. 
During the third quarter of 2012, the UK government enacted
legislation to restrict the combined corporate and supplementary
income tax relief on UK North Sea decommissioning expenditures to
50%. As a result of the income tax rate change, the Company's
deferred income tax liability was increased by $58 million. 
During the first quarter of 2011, the UK government enacted
legislation to increase the supplementary income tax rate charged on
profits from UK North Sea crude oil and natural gas production,
increasing the combined corporate and supplementary income tax rate
from 50% to 62%. As a result of the income tax rate change, the
Company's deferred income tax liability was increased by $104 million
as at March 31, 2011. 
During 2011, the Canadian federal government enacted legislation to
implement several taxation changes. These changes include a
requirement that, beginning in 2012, partnership income must be
included in the taxable income of each corporate partner based on the
tax year of the partner, rather than the fiscal year of the
partnership. The legislation includes a five-year transition
provision and has no impact on net earnings. 
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 o
f these matters will have a
material impact upon the Company's results of operations, financial
position or liquidity. 
For 2013, based on budgeted prices and the current availability of
tax pools, the Company expects to incur current income tax expense of
$550 million to $650 million in Canada and $10 million to $100
million in the North Sea and Offshore Africa. 
NET CAPITAL EXPENDITURES (1) 


 
                             Three Months Ended              Year Ended
                    --------------------------------------------------------
                         Dec 31     Sep 30     Dec 31      Dec 31     Dec 31
($ millions)               2012       2012       2011        2012       2011
----------------------------------------------------------------------------
Exploration and
 Evaluation
Net expenditures     $       10 $       59 $      112  $      309 $      312
----------------------------------------------------------------------------
Property, Plant and
 Equipment
Net property
 acquisitions                76         23        396         144      1,012
Well drilling,
 completion and
 equipping                  566        485        585       1,902      1,878
Production and
 related facilities         495        533        480       1,978      1,690
Capitalized interest
 and other (2)               23         28         26         111        104
----------------------------------------------------------------------------
Net expenditures          1,160      1,069      1,487       4,135      4,684
----------------------------------------------------------------------------
Total Exploration
 and Production           1,170      1,128      1,599       4,444      4,996
----------------------------------------------------------------------------
Oil Sands Mining and
 Upgrading
Horizon Phases 2/3
 construction costs         423        354        150       1,315        481
Sustaining capital           94         41         44         223        170
Turnaround cos
ts              5         11          -          21         79
Capitalized interest
 and other (2)               19         24         33          51         48
----------------------------------------------------------------------------
Total Oil Sands
 Mining and
 Upgrading                  541        430        227       1,610        778
----------------------------------------------------------------------------
Horizon coker
 rebuild and
 collateral damage
 costs (3)                    -          -         15           -        404
Midstream                     4          5          -          14          5
Abandonments (4)             41         48         66         204        213
Head office                  11         10          2          36         18
----------------------------------------------------------------------------
Total net capital
 expenditures        $    1,767 $    1,621 $    1,909  $    6,308 $    6,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America        $    1,086 $    1,029 $    1,546  $    4,126 $    4,736
North Sea                    55         79         71         254        227
Offshore Africa              29         20        (18)         64         33
Oil Sands Mining and
 Upgrading                  541        430        242       1,610      1,182
Midstream                     4          5          -          14          5
Abandonments (4)             41         48         66         204        213
Head office                  11         10          2          36         18
----------------------------------------------------------------------------
Total                $    1,767 $    1,621 $    1,909  $    6,308 $    6,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) The net capital expenditures exclude adjustments related to
differences between carrying amounts and tax values, and other fair
value adjustments. 
(2) Capitalized interest and other includes expenditures related to
land acquisition and retention, seismic, and other adjustments. 
(3) During 2011, the Company recognized $393 million of property
damage insurance recoveries (see note 7 to the interim consolidated
financial statements), offsetting the costs incurred related to the
coker rebuild and collateral damage costs. 
(4) Abandonments represent expenditures to settle asset retirement
obligations and have been reflected as capital expenditures in this
table. 
The Company's strategy is focused on building a diversified asset
base that is balanced among various products. In order to facilitate
efficient operations, the Company concentrates its activities in core
areas. The Company focuses on maintaining its land inventories to
enable the continuous exploitation of play types and geological
trends, greatly reducing overall exploration risk. By owning
associated infrastructure, the Company is able to maximize
utilization of its production facilities, thereby increasing control
over production costs. 
Net capital expenditures for the year ended December 31, 2012 were
$6,308 million, comparable with $6,414 million for the year ended
December 31, 2011. Net capital expenditures for the fourth quarter of
2012 were $1,767 million compared with $1,909 million for the fourth
quarter of 2011 and $1,621 million for the third quarter of 2012. 
The increase in capital expenditures in the Exploration and
Production and Oil Sands Mining and Upgrading segments for the year
ended December 31, 2012 from the comparable period in 2011 was
primarily due to the ramp up of Horizon site construction activity
and an increase in production and related facilities spending,
partially offset by lower net property acquisition costs. The
decrease in capital expenditures for the fourth quarter of 2012 from
the comparable period in 2011 was due to lower exploration and
evaluation expenditures and lower net property acquisitions,
partially offset by an increase in Horizon site construction costs.
The increase in capital expenditures from the third quarter of 2012
was primarily due to an increase in well drilling and completion
activities and an increase in Horizon site construction activity. 
Drilling Activity (number of wells) 


 
                                                                     Year
                                     Three Months Ended             Ended
                          --------------------------------------------------
                             Dec 31    Sep 30    Dec 31    Dec 31    Dec 31
                               2012      2012      2011      2012      2011
----------------------------------------------------------------------------
Net successful natural gas
 wells                            3         9        27        35        83
Net successful crude oil
 wells (1)                      294       365       330     1,203     1,103
Dry wells                        19         6        17        33        48
Stratigraphic test /
 service wells                  116        22       112       727       657
----------------------------------------------------------------------------
Total                           432       402       486     1,998     1,891
Success rate (excluding
 stratigraphic test /
 service wells)                  94%       99%       95%       97%       96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Includes bitumen wells. 
North America 
North America, excluding Oil Sands Mining and Upgrading, accounted
for approximately 69% of the total capital expenditures for the year
ended December 31, 2012 compared with approximately 77% for the year
ended December 31, 2011. 
During the fourth quarter of 2012, the Company targeted 
3 net natural
gas wells, including 1 well in Northeast British Columbia and 2 wells
in Northwest Alberta. The Company also targeted 313 net crude oil
wells. The majority of these wells were concentrated in the Company's
Northern Plains region where 226 primary heavy crude oil wells, 15
Pelican Lake heavy crude oil wells, 2 light crude oil wells and 38
bitumen (thermal oil) wells were drilled. Another 32 wells targeting
light crude oil were drilled outside the Northern Plains region. 
Overall Primrose thermal production for the fourth quarter of 2012
averaged approximately 121,000 bbl/d compared with approximately
78,000 bbl/d for the fourth quarter of 2011 and approximately 102,000
bbl/d for the third quarter of 2012. Production volumes were in line
with expectations due to the cyclic nature of thermal production at
Primrose. As part of the phased expansion of its in situ Oil Sands
assets, the Company is continuing to develop its Primrose thermal
projects. Additional pad drilling was completed and drilled on
budget, with these wells coming on production in 2013. 
The next planned phase of the Company's in situ Oil Sands assets
expansion is the Kirby South Phase 1 Project. As at December 31,
2012, the overall project was 81% complete, drilling was completed on
the fifth of seven pads, and first steam is targeted for late 2013.
In 2012, the Company acquired approximately 49 sections (12,630
hectares) of additional Oil Sands rights immediately adjacent to the
Kirby Project. 
Development of the tertiary recovery conversion projects at Pelican
Lake continued and 15 horizontal wells were drilled during the
quarter. Pelican Lake production averaged approximately 36,000 bbl/d
for the fourth quarter of 2012 compared with 40,000 bbl/d for the
fourth quarter of 2011 and 41,000 bbl/d for the third quarter of
2012. The decrease in production in the fourth quarter of 2012 from
the third quarter of 2012 was a result of facility constraints, which
will be alleviated as a result of the completion of the new 20,000
bbl/d battery expansion targeted to be on stream in the second
quarter of 2013. With this incremental capacity, both Woodenhouse and
Pelican production volumes will no longer be restricted. 
For the first quarter of 2013, the Company's overall planned drilling
activity in North America is expected to be 265 net crude oil wells,
31 net bitumen wells and 15 net natural gas wells, excluding
stratigraphic and service wells. 
Oil Sands Mining and Upgrading 
Phase 2/3 expansion activity in the fourth quarter of 2012 was
focused on the field construction of the gas recovery unit, sulphur
recovery unit, butane treatment unit, coker expansion, and extraction
trains 3 and 4, along with engineering related to the hydrogen and
hydrotreater units, vacuum distillation unit and distillation
recovery unit. 
North Sea 
In December 2011, the Banff FPSO and subsea infrastructure suffered
storm damage. Operations at Banff/Kyle, with combined net production
of approximately 3,500 bbl/d, were suspended. The FPSO and associated
floating storage unit have subsequently been removed from the field
and the FPSO is currently in dry dock for assessment of the damage
and repair timeframe. The extent of the property damage, including
associated costs, is not expected to be significant. 
In September 2012, the UK government announced the implementation of
the Brownfield Allowance, which allows for an agreed allowance
related to property development for certain pre-approved qualifying
field developments. This allowance partially mitigates the impact of
previous tax increases. The Company is currently assessing the impact
of this initiative on its future capital programs. 
The Company currently plans to decommission the Murchison platform in
the North Sea commencing in 2014 and estimates the decommissioning
efforts will continue for approximately 5 years. 
Offshore Africa 
During the fourth quarter of 2011, the Company sanctioned an 8 well
drilling program at the Espoir field in Cote d'Ivoire. Preparations
are ongoing and a drilling rig is on-site in preparation for the
commencement of the drilling program in 2013. At the Olowi field in
Gabon, approximately 1,500 bbl/d of production was shut in due to a
failure in the midwater arch. The Company currently has a vessel
on-site assessing the operability of the midwater arch. 
LIQUIDITY AND CAPITAL RESOURCES 


 
                                        ------------------------------------
                                             Dec 31      Sep 30      Dec 31
($ millions, except ratios)                    2012        2012        2011
----------------------------------------------------------------------------
Working capital (deficit) (1)            $   (1,264) $   (1,002) $     (894)
Long-term debt (2) (3)                   $    8,736  $    8,416  $    8,571
 
Share capital                            $    3,709  $    3,691  $    3,507
Retained earnings                            20,516      20,383      19,365
Accumulated other comprehensive income           58          46          26
----------------------------------------------------------------------------
Shareholders' equity                     $   24,283  $   24,120  $   22,898
 
Debt to book capitalization (3) (4)              26%         26%         27%
Debt to market capitalization (3) (5)            22%         20%         17%
After-tax return on average common
 shareholders' equity (6)                         8%         10%         12%
After-tax return on average capital
 employed (3) (7)                                 7%          8%         10%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Calculated as current assets less current liabilities, excluding
the current portion of long-term debt. 
(2) Includes the current portion of long-term debt. 
(3) Long-term debt is stated at its carrying value, net of fair value
adjustments, original issue discounts and transaction costs. 
(4) Calculated as current and long-term debt; divided by the book
value of common shareholders' equity plus current and long-term debt. 
(5) Calculated as current and long-term debt; divided by the market
value of common shareholders' equity plus current and long-term debt. 
(6) Calculated as net earnings for the twelve month trailing period;
as a percentage of average common shareholders' equity for the
period. 
(7) Calculated as net earnings plus after-tax interest and other
financing costs for the twelve month trailing period; as a percentage
of average capital employed for the period. 
At December 31, 2012, the Company's capital resources consisted
primarily of cash flow from operations, available bank credit
facilities and access to debt capital markets. Cash flow from
operations and the Company's ability to renew existing bank credit
facilities and raise new debt is dependent on factors discussed in
the "Risks and Uncertainties" section of the Company's December 31,
2011 annual MD&A. In addition, the Company's ability to renew
existing bank credit facilities and raise new debt is also dependent
upon maintaining an investment grade debt rating and the condition of
capital and credit markets. The Company continues to believe that its
internally generated cash flow from operations supported by the
implementation of its ongoing hedge policy, the flexibility of its
capital expenditure programs supported by its multi-year financial
plans, its existing bank credit facilities, and its ability to raise
new debt on commercially acceptable terms will provide sufficient
liquidity to sustain its operations in the short, medium and long
term and support its growth strategy. At December 31, 2012, the
Company had $3,661 million of available credit under its bank credit
facilities. 
During the second quarter of 2012, the Company's $1,500 million
revolving syndicated credit facility was extended to June 2016.
Additionally, the Company issu
ed $500 million of 3.05% medium-term
notes due June 2019. Proceeds from the securities issued were used to
repay bank indebtedness and for general corporate purposes. After
issuing these securities, the Company has $2,500 million remaining on
its outstanding $3,000 million base shelf prospectus that allows for
the issue of medium-term notes in Canada, which expires in November
2013. If issued, these securities will bear interest as determined at
the date of issuance. 
During the fourth quarter of 2012, the Company repaid US$350 million
of 5.45% unsecured notes. The Company has US$2,000 million remaining
on its outstanding US$3,000 million base shelf prospectus that allows
for the issue of US dollar debt securities in the United States,
which expires in November 2013. If issued, these securities will bear
interest as determined at the date of issuance. 
Subsequent to December 31, 2012, $400 million of 4.50% medium term
notes and US$400 million of 5.15% unsecured notes were repaid. This
indebtedness was retired utilizing cash flow from operations
generated in excess of capital expenditures and available bank credit
facilities as necessary, while maintaining the ongoing dividend
program. On a pro forma basis, reflecting the retirement of this
indebtedness at December 31, 2012, the available credit under its
bank credit facilities would amount to $2,863 million. 
Long-term debt was $8,736 million at December 31, 2012, resulting in
a debt to book capitalization ratio of 26% (September 30, 2012 - 26%;
December 31, 2011 - 27%). This ratio is within the 25% to 45%
internal range utilized by management. This range may be exceeded in
periods when a combination of capital projects, acquisitions, or
lower commodity prices occurs. The Company may be below the low end
of the targeted range when cash flow from operating activities is
greater than current investment activities. The Company remains
committed to maintaining a strong balance sheet, adequate available
liquidity and a flexible capita
l structure. The Company has hedged a
portion of its crude oil production for 2013 at prices that protect
investment returns to ensure ongoing balance sheet strength and the
completion of its capital expenditure programs. Further details
related to the Company's long-term debt at December 31, 2012 are
discussed in note 5 to the Company's unaudited interim consolidated
financial statements. 
The Company's commodity hedging policy reduces the risk of volatility
in commodity prices and supports the Company's cash flow for its
capital expenditures programs. This policy currently allows for the
hedging of up to 60% of the near 12 months budgeted production and up
to 40% of the following 13 to 24 months estimated production. For the
purpose of this policy, the purchase of put options is in addition to
the above parameters. As at March 6, 2013, approximately 48% of
currently forecasted 2013 crude oil volumes were hedged using price
collars. Further details related to the Company's commodity related
derivative financial instruments outstanding at December 31, 2012 are
discussed in note 13 to the Company's unaudited interim consolidated
financial statements. 
Share Capital 
As at December 31, 2012, there were 1,092,072,000 common shares
outstanding and 73,747,000 stock options outstanding. As at March 5,
2013, the Company had 1,092,589,000 common shares outstanding and
68,482,000 stock options outstanding. 
During the second quarter of 2012, the Company amended its Articles
by special resolution of the Shareholders, changing the designation
of its Class 1 preferred shares to "Preferred Shares" which may be
issuable in series. If issued, the number of shares in each series,
and the designation, rights, privileges, restrictions and conditions
attached to the shares will be determined by the Board of Directors
of the Company. 
On March 6, 2013, the Company's Board of Directors approved an
increase in the annual dividend to be paid by the Company to $0.50
per common share for 2013. The increase represents an approximately
19% increase from 2012, recognizing the stability of the Company's
cash flow and providing a return to shareholders. The dividend policy
undergoes periodic review by the Board of Directors and is subject to
change. In March 2012, an increase in the annual dividend paid by the
Company to $0.42 per common share was approved for 2012. The increase
represented a 17% increase from 2011. 
In April 2012, the Company announced a Normal Course Issuer Bid to
purchase, through the facilities of the Toronto Stock Exchange
("TSX") and the New York Stock Exchange ("NYSE"), during the twelve
month period commencing April 9, 2012 and ending April 8, 2013, up to
55,027,447 common shares. 
On March 31, 2011, the Company announced a Normal Course Issuer Bid
to purchase, through the facilities of the TSX and the NYSE, during
the twelve month period commencing April 6, 2011 and ending April 5,
2012, up to 27,406,131 common shares of the Company. 
As at December 31, 2012, 11,012,700 common shares were purchased for
cancellation at a weighted average price of $28.91 per common share,
for a total cost of $318 million. 
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS 
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's future
operations. As at December 31, 2012, no entities were consolidated
under the Standing Interpretations Committee ("SIC") 12,
"Consolidation - Special Purpose Entities". The following table
summarizes the Company's commitments as at December 31, 2012: 


 
($ millions)     2013       2014       2015       2016       2017 Thereafter
----------------------------------------------------------------------------
Product
 transport
 ation and
 pipeline   $     231 $      218 $      204 $      135 $      117 $      788
Offshore
 equipment
 operating
 leases
 and
 offshore
 drilling  $    156 $      135 $      104 $       76 $       57 $       65
Long-term
 debt (1)  $    798 $      846 $      593 $    1,027 $    1,094 $    4,430
Interest
 and other
 financing
 costs (2) $    414 $      395 $      359 $      338 $      283 $    3,782
Office
 leases    $     33 $       34 $       32 $       33 $       35 $      262
Other      $    173 $       95 $       43 $       10 $        2 $        7
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
(1) Long-term debt represents principal repayments only and does not
reflect fair value adjustments, original issue discounts or
transaction costs. 
(2) Interest and other financing cost amounts represent the scheduled
fixed rate and variable rate cash interest payments related to
long-term debt. Interest on variable rate long-term debt was
estimated based upon prevailing interest rates and foreign exchange
rates as at December 31, 2012. 
In addition to the commitments disclosed above, the Company has
entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These
contracts can be cancelled by the Company upon notice without
penalty, subject to the costs incurred up to and in respect of the
cancellation. 
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES 
The Company is a defendant and plaintiff in a number of legal actions
arising in the normal course of business. In addition, the Company is
subject to certain contractor construction claims. The Company
believes that any liabilities that might arise pertaining to any such
matters would not have a material effect on its consolidated
financial position. 
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED 
For the impact of new accounting standards, refer to the MD&A and the
audited consolidated financial statements for the year ended December
31, 2011. 
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING POLICIES 
The preparation of financial statements requires the Company to make
estimates
, assumptions and 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 accounting policies is contained in the MD&A
and the audited consolidated financial statements for the year ended
December 31, 2011. 
Consolidated Balance Sheets 


 
                                            --------------------------------
As at                                                   Dec 31       Dec 31
(millions of Canadian dollars, unaudited)   Note          2012          2011
----------------------------------------------------------------------------
ASSETS
Current assets
  Cash and cash equivalents                      $          37 $          34
  Accounts receivable                                    1,197         2,077
  Inventory                                                554           550
  Prepaids and other                                       126           120
----------------------------------------------------------------------------
                                                         1,914         2,781
Exploration and evaluation assets             2          2,611         2,475
Property, plant and equipment                 3         44,028        41,631
Other long-term assets                        4            427           391
----------------------------------------------------------------------------
                                                 $      48,980 $      47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
LIABILITIES
Current liabilities
  Accounts payable                               $         465 $         526
  Accrued liabilities                                    2,273         2,347
  Current income tax liabilities                           285           347
  Current portion of long-term debt           5            798           359
  Current portion of other long-term
   liabilities                                6            155           455
----------------------------------------------------------------------------
                                                         3,976         4,034
Long-term debt                                5          7,938         8,212
Other long-term liabilities                   6          4,609         3,913
Deferred income tax liabilities                          8,174         8,221
----------------------------------------------------------------------------
                                                        24,697        24,380
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital                                 9          3,709         3,507
Retained earnings                                       20,516        19,365
Accumulated other comprehensive income       10             58            26
----------------------------------------------------------------------------
                                                        24,283        22,898
----------------------------------------------------------------------------
                                                 $      48,980 $      47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Commitments and contingencies (note 14). 
Approved by the Board of Directors on March 6, 2013 
Consolidated Statements of Earnings 


 
                               Three Months Ended          Year Ended
                            ------------------------------------------------
(millions of Canadian
 dollars, except per
 common share amounts,           Dec 31     Dec 31      Dec 31      Dec 31
 unaudited)             Note       2012        2011        2012        2011
----------------------------------------------------------------------------
Product sales                $    4,059  $    4,788  $   16,195  $   15,507
Less: royalties                    (359)       (570)     (1,606)     (1,715)
----------------------------------------------------------------------------
Revenue                           3,700       4,218      14,589      13,792
----------------------------------------------------------------------------
Expenses
Production                        1,072       1,034       4,249       3,671
Transportation and
 blending                           738         582       2,752       2,327
Depletion, depreciation
 and amortization         3       1,213         998       4,328       3,604
Administration                       64          47         270         235
Share-based compensation  6         (41)        207        (214)       (102)
Asset retirement
 obligation accretion     6          38          33         151         130
Interest and other
 financing costs                     83          83         364         373
Risk management
 activities              13           -          78         120         (27)
Foreign exchange loss
 (gain)                              58        (106)        (49)          1
Horizon asset impairment
 provision                7           -           -           -         396
Insurance recovery -
 property damage          7           -           3           -        (393)
Insurance recovery -
 business interruption    7           -         (16)          -        (333)
Equity loss from jointly
 controlled entity        4           3           -           9           -
----------------------------------------------------------------------------
                                  3,228       2,943      11,980       9,882
----------------------------------------------------------------------------
Earnings before taxes               472       1,275       2,609       3,910
Current income tax
 expense                  8         189         299         747         860
Deferred income tax
 (recovery) expense       8         (69)        144         (30)        407
----------------------------------------------------------------------------
Net earnings                 $      352  $      832  $    1,892  $    2,643
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common
 share
Basic                    12  $     0.32  $     0.76  $     1.72  $     2.41
Diluted                  12  $     0.32  $     0.76  $     1.72  $     2.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Consolidated Statements of Comprehensive Income 


 
                            ------------------------------------------------
                               Three Months Ended          Year Ended
                            ------------------------------------------------
(millions of Canadian            Dec 31     Dec 31      Dec 31      Dec 31
 dollars, unaudited)               2012        2011        2012        2011
----------------------------------------------------------------------------
Net earnings                 $      352  $      832  $    1,892  $    2,643
----------------------------------------------------------------------------
Net change in derivative
 financial instruments
 designated as cash flow
 hedges
  Unrealized income (loss)
   during the period, net of
   taxes of $2 million (2011
   - $10 million) - three
   months ended;$4 million
   (2011 - $5 million) -
   year ended                        17         (67)         31         (23)
  Reclassification to net
   earnings, net of taxes of
   $nil (2011 - $4 million)
   - three months ended;$nil
   (2011 - $17 million) -
   year ended                        (3)         11          (7)   
      52
----------------------------------------------------------------------------
                                     14         (56)         24          29
Foreign currency translation
 adjustment
  Translation of net
   investment                        (2)         11           8         (12)
----------------------------------------------------------------------------
Other comprehensive income
 (loss), net of taxes                12         (45)         32          17
----------------------------------------------------------------------------
Comprehensive income         $      364  $      787  $    1,924  $    2,660
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Consolidated Statements of Changes in Equity 


 
                                                        Year Ended
                                              ------------------------------
                                                      Dec 31         Dec 31
(millions of Canadian dollars, unaudited) Note          2012           2011
----------------------------------------------------------------------------
Share capital                               9
Balance - beginning of year                    $       3,507  $       3,147
Issued upon exercise of stock options                    194            255
Previously recognized liability on stock
 options exercised for common shares                      45            115
Purchase of common shares under Normal
 Course Issuer Bid                                       (37)           (10)
----------------------------------------------------------------------------
Balance - end of year                                  3,709          3,507
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of year                           19,365         17,212
Net earnings                                           1,892          2,643
Purchase of common shares under Normal
 Course Issuer Bid                          9           (281)           (94)
Dividends on common shares                  9           (460)          (396)
----------------------------------------------------------------------------
Balance - end of year                                 20,516         19,365
----------------------------------------------------------------------------
Accumulated other comprehensive income     10
Balance - beginning of year                               26              9
Other comprehensive income, net of taxes                  32             17
----------------------------------------------------------------------------
Balance - end of year                                     58             26
----------------------------------------------------------------------------
Shareholders' equity                           $      24,283  $      22,898
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Consolidated Statements of Cash Flows 


 
                                Three Months Ended          Year Ended
                            ------------------------------------------------
(millions of Canadian               Dec 31    Dec 31     Dec 31     Dec 31
 dollars, unaudited)        Note      2012       2011       2012       2011
----------------------------------------------------------------------------
Operating activities
Net earnings                     $     352  $     832  $   1,892  $   2,643
Non-cash items
  Depletion, depreciation
   and amortization                  1,213        998      4,328      3,604
  Share-based compensation             (41)       207       (214)      (102)
  Asset retirement
   obligation accretion                 38         33        151        130
  Unrealized risk management
   loss (gain)                           8         58        (42)      (128)
  Unrealized foreign
   exchange loss (gain)                254       (117)       129        215
  Realized foreign exchange
   gain on repayment of US
   dollar debt securities             (210)         -       (210)      (225)
  Equity loss from jointly
   controlled entity                     3          -          9          -
  Deferred income tax
   (recovery) expense                  (69)       144        (30)       407
  Horizon asset impairment
   provision                  7          -          -          -        396
Insurance recovery -
 property damage              7          -          3          -       (393)
Other                                  (94)       (46)       (47)       (55)
Abandonment expenditures               (41)       (66)      (204)      (213)
Net change in non-cash
 working capital                       202        267        447        (36)
----------------------------------------------------------------------------
                                     1,615      2,313      6,209      6,243
----------------------------------------------------------------------------
Financing activities
Issue (repayment) of bank
 credit facilities, net                592     (1,632)       172       (647)
Issue of medium-term notes,
 net                                     -          -        498          -
(Repayment) issue of US
 dollar debt securities, net  5       (344)     1,011       (344)       621
Issue of common shares on
 exercise of stock options              30         63        194        255
Purchase of common shares
 under Normal Course Issuer
 Bid                                  (118)       (12)      (318)      (104)
Dividends on common shares            (115)       (99)      (444)      (378)
Net change in non-cash
 working capital                        (8)        (5)       (37)       (15)
----------------------------------------------------------------------------
                                        37       (674)      (279)      (268)
----------------------------------------------------------------------------
Investing activities
Expenditures on exploration
 and evaluation assets and
 property, plant and
 equipment                          (1,726)    (1,843)    (6,104)    (6,201)
Investment in other long-
 term assets                             -         25          2       (321)
Net change in non-cash
 working capital                        90        195        175        559
----------------------------------------------------------------------------
                                    (1,636)    (1,623)    (5,927)    (5,963)
----------------------------------------------------------------------------
Increase in cash and cash
 equivalents                            16         16          3         12
Cash and cash equivalents -
 beginning of period                    21         18         34         22
----------------------------------------------------------------------------
Cash and cash equivalents
 -end of period                  $      37  $      34  $      37  $      34
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid                    $     104  $      80  $     464  $     456
Income taxes paid                $     105  $     190  $     639  $     706
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
                                                         Oil Sands
                                                         Mining and
                        Exploration and Production        Upgrading   Total
----------------------------------------------------------------------------
                      North                   Offshore
                    America     North Sea
       Africa
----------------------------------------------------------------------------
Cost
At December 31,
 2011              $  2,442  $          - $         33 $          - $ 2,475
Additions               295             -           14            -     309
Transfers to
 property, plant
 and equipment         (173)            -            -            -    (173)
----------------------------------------------------------------------------
At December 31,
 2012              $  2,564  $          - $         47 $          - $ 2,611
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
3. PROPERTY, PLANT AND EQUIPMENT 


 
                                          Exploration and Production
----------------------------------------------------------------------------
                                          North                    Offshore
                                        America     North Sea        Africa
----------------------------------------------------------------------------
Cost
At December 31, 2011              $      46,120 $       4,147 $       3,044
Additions                                 4,160           556            75
Transfers from E&E
 assets                                     173             -             -
Disposals/
 derecognitions                            (129)          (39)           (8)
Foreign exchange
 adjustments and
 other                                        -           (90)          (66)
----------------------------------------------------------------------------
At December 31, 2012              $      50,324 $       4,574 $       3,045
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and depreciation
At December 31, 2011              $      21,721 $       2,512 $       2,152
Expense                                   3,399           294           165
Disposals/
 derecognitions                            (129)          (39)           (6)
Foreign exchange
 adjustments and
 other                                        -           (58)          (38)
----------------------------------------------------------------------------
At December 31, 2012              $      24,991 $       2,709 $       2,273
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value- at
 December 31, 2012                $      25,333 $       1,865 $         772
- at December 31,
 2011                             $      24,399 $       1,635 $         892
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                        Oil Sands
                       Mining and
                        Upgrading      Midstream   Head Office        Total
----------------------------------------------------------------------------
 
----------------------------------------------------------------------------
Cost
At December 31, 2011$      15,211 $          298$          234$      69,054
Additions                   1,757             14            36        6,598
Transfers from E&E
 assets                         -              -             -          173
Disposals/
 derecognitions                (5)             -             -         (181)
Foreign exchange
 adjustments and
 other                          -              -             -         (156)
----------------------------------------------------------------------------
At December 31, 2012$      16,963 $          312$          270$      75,488
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
 depletion and
 depreciation
At December 31, 2011$         776 $           96$          166$      27,423
Expense                       447              7            16        4,328
Disposals/
 derecognitions                (5)             -             -         (179)
Foreign exchange
 adjustments and
 other                        (16)             -             -         (112)
----------------------------------------------------------------------------
At December 31, 2012$       1,202 $          103$          182$      31,460
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value- at
 December 31, 2012  $      15,761 $          209$           88$      44,028
- at December 31,
 2011               $      14,435 $          202$           68$      41,631
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
 
Horizon project costs not subject to depletion
----------------------------------------------------------------------------
At December 31, 2012                                              $    2,066
At December 31, 2011                                              $    1,443
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
In addition, the Company has capitalized costs to date of $1,021
million (2011 - $528 million) related to the development of the Kirby
Thermal Oil Sands Project which are not subject to depletion. 
During 2012, the Company acquired a number of producing crude oil and
natural gas assets in the North American Exploration and Production
segment for total cash consideration of $144 million (year ended
December 31, 2011 - $1,012 million), net of associated asset
retirement obligations of $12 million (year ended December 31, 2011 -
$79 million). Interests in jointly control
led assets were acquired
with full tax basis. No working capital or debt obligations were
assumed. 
The Company capitalizes construction period interest for qualifying
assets based on costs incurred and the Company's cost of borrowing.
Interest capitalization to a qualifying asset ceases once
construction is substantially complete. During 2012, pre-tax interest
of $98 million was capitalized to property, plant and equipment
(December 31, 2011 - $59 million) using a capitalization rate of 4.8%
(December 31, 2011 - 4.7%). 
4. OTHER LONG-TERM ASSETS 


 
                                                   -------------
                                                         Dec 31       Dec 31
                                                           2012         2011
----------------------------------------------------------------------------
Investment in North West Redwater Partnership      $        310 $        321
Other                                                       117           70
----------------------------------------------------------------------------
                                                   $        427 $        391
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Other long-term assets include an investment in the 50% owned
Redwater. The investment is accounted for using the equity method.
Redwater has entered into an agreement to construct and operate a
50,000 barrel per day bitumen upgrader and refinery (the "Project")
under processing agreements that target to process 12,500 barrels per
day of bitumen feedstock for the Company and 37,500 barrels per day
of bitumen feedstock for the Alberta Petroleum Marketing Commission,
an agent of the Government of Alberta, under a 30 year
fee-for-service tolling agreement. During 2012, the Project received
board sanction from Redwater and its partners. 
Redwater has entered into various agreements 
related to the
engineering and procurement of the Project. These contracts can be
cancelled by Redwater upon notice without penalty, subject to the
costs incurred up to and in respect of the cancellation. 
5. LONG-TERM DEBT 


 
                                                    ------------
                                                         Dec 31      Dec 31
                                                           2012        2011
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities                                $     971   $     796
Medium-term notes                                         1,300         800
----------------------------------------------------------------------------
                                                          2,271       1,596
----------------------------------------------------------------------------
US dollar denominated debt
US dollar debt securities (December 31, 2012 -
 US$6,550 million; December 31, 2011 - US$6,900
 million)                                                 6,517       7,017
Less: original issue discount on US dollar debt
 securities (1)                                             (20)        (21)
----------------------------------------------------------------------------
                                                          6,497       6,996
Fair value impact of interest rate swaps on US
 dollar debt securities (2)                                  19          31
----------------------------------------------------------------------------
                                                          6,516       7,027
----------------------------------------------------------------------------
Long-term debt before transaction costs                   8,787       8,623
Less: transaction costs (1) (3)                             (51)        (52)
----------------------------------------------------------------------------
                                                          8,736       8,571
Less: current portion (1) (2) (4)                           798         359
----------------------------------------------------------------------------
                                                      $   7,938   $   8,212
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
(1) The Company has included unamortized original issue discounts and
    directly attributable transaction costs in the carrying amount of the
    outstanding debt.
(2) The carrying amount of US$350 million of 4.90% unsecured notes due
    December 2014 was adjusted by $19 million to reflect the fair
    value impact of hedge accounting. At December 31, 2011, the
    carrying amounts of US$350 million of 5.45% unsecured notes
    due October 2012 and US$350 million of 4.90% unsecured notes due
    December 2014 were adjusted by $31 million to reflect the fair value
    impact of hedge accounting.
(3) Transaction costs primarily represent underwriting commissions charged
    as a percentage of the related debt offerings, as well as legal, rating
    agency and other professional fees.
(4) Subsequent to December 31, 2012, $400 million of 4.50% medium term notes
    due January 2013 and US$400 million of 5.15% unsecured notes due
    February 2013 were repaid. This indebtedness was retired utilizing cash
    flow from operating activities generated in excess of capital
    expenditures and available bank credit facilities as necessary.

 
Bank Credit Facilities 
As at December 31, 2012, the Company had in place unsecured bank
credit facilities of $4,724 million, comprised of: 
-- a $200 million demand credit facility; 
-- a revolving syndicated credit facility of $3,000 million maturing
June 2015; 
-- a revolving syndicated credit facility of $1,500 million maturing
June 2016; and 
-- a GBP 15 million demand credit facility related to the Company's
North Sea operations. 
During the second quarter of 2012, the $1,500 million revolving
syndicated credit facility was extended to June 2016. Each of the
$3,000 million and $1,500 million facilities is extendible annually
for one-year periods at the mutual agreement of the Company and the
lenders. If the facilities are not extended, the full amount of the
outstanding principal would be repayable on the maturity date.
Borrowings under these facilities may be made by way of pricing
referenced to Canadian dollar or US dollar bankers' acceptances, or
LIBOR, US base rate or Canadian prime loans. 
The Company's weighted average interest rate on bank credit
facilities outstanding as at December 31, 2012, was 2.2% (December
31, 2011 - 2.2%), and on long-term debt outstanding for the year
ended December 31, 2012 was 4.8% (December 31, 2011 - 4.7%). 
In addition to the outstanding debt, letters of credit and financial
guarantees aggregating $467 million, including an $87 million
financial guarantee related to Horizon and $276 million of letters of
credit related to North Sea operations, were outstanding at December
31, 2012. Subsequent to December 31, 2012, the letter of credit
related to North Sea operations was increased to $347 million. 
Medium-Term Notes 
During the second quarter of 2012, the Company issued $500 million of
3.05% medium-term notes due June 2019. After issuing these
securities, the Company has $2,500 million remaining on its
outstanding $3,000 million base shelf prospectus that allows for the
issue of medium-term notes in Canada, which expires in November 2013.
If issued, these securities will bear interest as determined at the
date of issuance. 
US Dollar Debt Securities 
During the fourth quarter of 2012, the Company repaid US$350 million
of 5.45% unsecured notes. 
During 2011, the Company repaid US$400 million of 6.70% unsecured
notes and issued US$1,000 million of unsecured notes under the US
base shelf prospectus, comprised of US$500 million of 1
.45% unsecured
notes due November 2014 and US$500 million of 3.45% unsecured notes
due November 2021. Concurrently, the Company entered into cross
currency swaps to fix the Canadian dollar interest and principal
repayment amounts on the US$500 million of 3.45% unsecured notes due
November 2021 at 3.96% and C$511 million (note 13). 
The Company has US$2,000 million remaining on its outstanding
US$3,000 million base shelf prospectus that allows for the issue of
US dollar debt securities in the United States, which expires in
November 2013. If issued, these securities will bear interest as
determined at the date of issuance. 
6. OTHER LONG-TERM LIABILITIES 


 
                                                  -------------
                                                         Dec 31       Dec 31
                                                           2012         2011
----------------------------------------------------------------------------
Asset retirement obligations                       $      4,266 $      3,577
Share-based compensation                                    154          432
Risk management (note 13)                                   257          274
Other                                                        87           85
----------------------------------------------------------------------------
                                                          4,764        4,368
Less: current portion                                       155          455
----------------------------------------------------------------------------
                                                   $      4,609 $      3,913
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
The Company's asset retirement obligations are expected to be settled
on an ongoing basis over a period of approximately 60 years and have
been discounted using a weighted average discount rate of 4.3%
(December 31, 2011 - 4.6%). A reconciliation of the discounted asset
retirement obligations is as follows: 


 
                                                  -------------
                                                        Dec 31       Dec 31
                                                          2012         2011
----------------------------------------------------------------------------
Balance - beginning of year                        $     3,577  $     2,624
  Liabilities incurred                                      51           42
  Liabilities acquired                                      12           79
  Liabilities settled                                     (204)        (213)
  Asset retirement obligation accretion                    151          130
  Revision of estimates                                    384          472
  Change in discount rate                                  315          422
  Foreign exchange                                         (20)          21
----------------------------------------------------------------------------
Balance - end of year                              $     4,266  $     3,577
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Share-based compensation 
As the Company's Option Plan provides current employees with the
right to elect to receive common shares or a cash payment in exchange
for stock options surrendered, a liability for potential cash
settlements is recognized. The current portion represents the maximum
amount of the liability payable within the next twelve month period
if all vested stock options are surrendered for cash settlement. 


 
                                                  -------------
                                                        Dec 31       Dec 31
                                                          2012         2011
----------------------------------------------------------------------------
Balance - beginning of year                        $       432  $       663
  Share-based compensation recovery                       (214)        (102)
  Cash payment for stock options surrendered                (7)         (14)
  Transferred to common shares                             (45)        (115)
  Recovered from Oil Sands Mining and Upgrading            (12)           -
----------------------------------------------------------------------------
Balance - end of year                                      154          432
Less: current portion                                      129          384
----------------------------------------------------------------------------
                                                   $        25  $        48
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
                             Three Months Ended            Year Ended
                        ----------------------------------------------------
                             Dec 31        Dec 31       Dec 31      Dec 31
                                2012         2011         2012         2011
----------------------------------------------------------------------------
Current corporate income
 tax - North America     $        68  $       119  $       366  $       315
Current corporate income
 tax - North Sea                  29           84          115          245
Current corporate income
 tax - Offshore Africa            56           50          206          140
Current PRT (1) expense
 - North Sea                      31           39           44          135
Other taxes                        5            7           16           25
----------------------------------------------------------------------------
Current income tax
 expense                         189          299          747          860
----------------------------------------------------------------------------
Deferred corporate
 income tax (recovery)
 expense                         (34)         157            -          412
Deferred PRT (1)
 (recovery) - North Sea          (35)         (13)         (30)          (5)
----------------------------------------------------------------------------
Deferred income tax
 (recovery) expense              (69)         144          (30)         407
----------------------------------------------------------------------------
Income tax expense       $       120  $       443  $       717  $     1,267
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Petroleum Revenue Tax.

 
During the third quarter of 2012, the UK government enacted
legislation to restrict the combined corporate and supplementary
income tax relief on UK North Sea decommissioning expenditures to
50%. As a result of the income tax rate change, the Company's
deferred income tax liability was increased by $58 million. 
During the first quarter of 2011, the UK government enacted
legislation to increase the supplementary income tax rate charged on
profits from UK North Sea crude oil and natural gas production,
increasing the combined corporate and supplementary income tax rate
from 50% to 62%. As a result of the income tax rate change, the
Company's deferred income tax liability was increased by $104
million. 
During 2011, the Canadian federal government enacted legislation to
implement several taxation changes. These changes include a
requirement that, beginning in 2012, partnership income must be
included in the taxable income of each corporate partner based on the
tax year of the partner, rather than the fiscal year of the
partnership. The legislation includes a five-year transition
provision and has no impact on net earnings. 
9. SHARE CAPITAL 
Authorized 
Preferred shares issuable in a series. 
Unlimited number of common shares without par value. 


 
                                             -------------------------------
                                                 Year Ended Dec 31, 2012
                                              Number of shares
Issued common shares                                (thousands)      Amount
----------------------------------------------------------------------------
Balance - beginning of year                          1,096,460  $     3,507
Issued upon exercise of stock options                    6,625          194
Previously recognized liability on stock
 options exercised for common shares                         -           45
Purchase of common shares under Normal Course
 Issuer Bid                                            (11,013)         (37)
----------------------------------------------------------------------------
Balance - end of year                                1,092,072  $     3,709
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Preferred Shares 
During the second quarter of 2012, the Company amended its Articles
by special resolution of the Shareholders, changing the designation
of its Class 1 preferred shares to "Preferred Shares" which may be
issuable in series. If issued, the number of shares in each series,
and the designation, rights, privileges, restrictions and conditions
attached to the shares will be determined by the Board of Directors
of the Company. 
Dividend Policy 
The Company has paid regular quarterly dividends in January, April,
July, and October of each year since 2001. The dividend policy
undergoes periodic review by the Board of Directors and is subject to
change. 
On March 6, 2013, the Board of Directors set the regular quarterly
dividend at $0.125 per common share (2012 - $0.105 per common share). 
Normal Course Issuer Bid 
The Company's Normal Course Issuer Bid announced in 2011 expired
April 5, 2012. In April 2012, the Company announced a Normal Course
Issuer Bid to purchase through the facilities of the Toronto Stock
Exchange and the New York Stock Exchange, during the twelve month
period commencing April 9, 2012 and ending April 8, 2013, up to
55,027,447 common shares. 
As at December 31, 2012, the Company purchased 11,012,700 common
shares at a weighted average price of $28.91 per common share, for a
total cost of $318 million. Retained earnings were reduced by $281
million, representing the excess of the purchase price of common
shares over their average carrying value. 
Stock Options 
The following table summarizes information relating to stock options
outstanding at December 31, 2012: 


 
                                              ------------------------------
                                                  Year Ended Dec 31, 2012
----------------------------------------------------------------------------
                                                                    Weighted
                                                                     average
                                               Stock options        exercise
                                                  (thousands)          price
----------------------------------------------------------------------------
Outstanding - beginning of year                       73,486  $        34.85
Granted (1)                                           14,779  $        29.27
Surrendered for cash settlement                         (998) $        29.82
Exercised for common shares                           (6,625) $        29.19
Forfeited (1)                                         (6,895) $        36.68
----------------------------------------------------------------------------
Outstanding - end of year                             73,747  $        34.13
----------------------------------------------------------------------------
Exercisable - end of year                             29,366  $        33.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to December 31, 2012, 3,479,000 stock options at a weighted
    average exercise price of $28.74 were granted and 8,228,000 stock
    options at a weighted average exercise price of $35.27 were forfeited.

 
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: 


 
                                                  -------------
                                                        Dec 31       Dec 31
                                                          2012         2011
----------------------------------------------------------------------------
Derivative financial instruments designated as
 cash flow hedges                                  $        86  $        62
Foreign currency translation adjustment                    (28)         (36)
----------------------------------------------------------------------------
                                                   $        58  $        26
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 December 31, 2012, the
ratio was within the target range at 26%. 
Readers are cautioned that the debt to book capitalization ratio is
not defined by IFRS and this financial measure may not be comparable
to similar measures presented by other companies. Further, there are
no assurances that the Company will continue to use this measure to
monitor capital or will not alter the method of calculation of this
measure in the future. 


 
                                                  -------------
                                                        Dec 31       Dec 31
                                                          2012         2011
----------------------------------------------------------------------------
Long-term debt (1)                                 $     8,736  $     8,571
Total shareholders' equity                         $    24,283  $    22,898
Debt to book capitalization                                 26%          27%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.

 
12. NET EARNINGS PER COMMON SHARE 


 
                             Three Months Ended            Year Ended
                        ----------------------------------------------------
                               Dec 31       Dec 31       Dec 31       Dec 31
                                 2012         2011         2012         2011
----------------------------------------------------------------------------
Weighted average common
 shares outstanding -
 basic (thousands of
 shares)                    1,093,925    1,095,072    1,097,084    1,095,582
Effect of dilutive stock
 options (thousands of
 shares)                        1,604        4,390        2,435        7,000
----------------------------------------------------------------------------
Weighted average common
 shares outstanding -
 diluted (thousands of
 shares)                    1,095,529    1,099,462    1,099,519    1,102,582
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings             $        352 $        832 $      1,892 $      2,643
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common
 share - basic           $       0.32 $       0.76 $       1.72 $       2.41
  - diluted              $ 
      0.32 $       0.76 $       1.72 $       2.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
              --------------------------------------------------------------
                                        Dec 31, 2012
----------------------------------------------------------------------------
                  Loans and       Fair                  Financial
                receivables      value                liabilities
                         at    through  Derivatives            at
Asset             amortized  profit or     used for     amortized
 (liability)           cost       loss      hedging          cost     Total
----------------------------------------------------------------------------
Accounts
 receivable    $      1,197 $        - $          -  $          -  $  1,197
Accounts
 payable                  -          -            -          (465)     (465)
Accrued
 liabilities              -          -            -        (2,273)   (2,273)
Other long-
 term
 liabilities              -          4         (261)          (79)     (336)
Long-term debt
 (1)                      -          -            -        (8,736)   (8,736)
----------------------------------------------------------------------------
               $      1,197 $        4 $       (261) $    (11,553) $(10,613)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                        Dec 31, 2011
----------------------------------------------------------------------------
 
                  Loans and      Fair                   Financial
                receivables     value                 liabilities
                         at   through   Derivatives            at
Asset            amortized     profit      used for    amortized
 (liability)           cost   or loss       hedging          cost     Total
----------------------------------------------------------------------------
Accounts
 receivable    $      2,077 $       -  $          -  $          -  $  2,077
Accounts
 payable                  -         -             -          (526)     (526)
Accrued
 liabilities              -         -             -        (2,347)   (2,347)
Other long-
 term
 liabilities              -       (38)         (236)          (75)     (349)
Long-term debt
 (1)                      -         -             -        (8,571)   (8,571)
----------------------------------------------------------------------------
               $      2,077 $     (38) $       (236) $    (11,519) $ (9,716)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.

 
The carrying amount of the Company's financial instruments
approximates their fair value, except for fixed rate long-term debt
as noted below. The fair values of the Company's other long-term
liabilities and fixed rate long-term debt are outlined below: 


 
                               ---------------------------------------------
                                                Dec 31, 2012
----------------------------------------------------------------------------
                                     Carrying
                                       amount                    Fair value
----------------------------------------------------------------------------
Asset (liability) (1)                                Level 1        Level 2
----------------------------------------------------------------------------
Other long-term liabilities     $        (257) $           -  $        (257)
Fixed rate long-term debt (2)
 (3) (4)                               (7,765)        (9,118)             -
----------------------------------------------------------------------------
                                $      (8,022) $      (9,118) $        (257)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                                Dec 31, 2011
----------------------------------------------------------------------------
                                     Carrying
                                       amount                    Fair value
----------------------------------------------------------------------------
Asset (liability) (1)                                Level 1        Level 2
----------------------------------------------------------------------------
Other long-term liabilities     $        (274) $           -  $        (274)
Fixed rate long-term debt (2)
 (3) (4)                               (7,775)        (9,120)             -
----------------------------------------------------------------------------
                                $      (8,049) $      (9,120) $        (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes financial assets and liabilities where the carrying amount
    approximates fair value due to the liquid nature of the asset or
    liability (cash and cash equivalents, accounts receivable, accounts
    payable and accrued liabilities).
(2) The carrying amount of US$350 million of 4.90% unsecured notes due
    December 2014 was adjusted by $19 million to reflect the fair value
    impact of hedge accounting. At December 31, 2011, the carrying
    amounts of US$350 million of 5.45% unsecured notes due October 2012
    and US$350 million of 4.90% unsecured notes due December 2014
    were adjusted by $31 million to reflect the fair value impact of
    hedge accounting.
(3) The fair value of fixed rate long-term debt has been determined based on
    quoted market prices.
(4) Includes the current portion of long-term debt.

 
The following provides a summary of the carrying amounts of
derivative contracts held and a reconciliation to the Company's
consolidated balance sheets. 


 
                                                  -------------
                                                       Dec 31,      Dec 31,
Asset (liability)                                         2012         2011
----------------------------------------------------------------------------
Derivatives held for trading
  Crude oil price collars                          $       (16) $       (13)
  Foreign currency forward contracts                        20          (25)
Cash flow hedges
  Cross currency swaps                                    (261)        (236)
----------------------------------------------------------------------------
                                                   $      (257) $      (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Included within:
  Current portion of other long-term liabilities   $        (4) $       (43)
  Other long-term liabilities                             (253)        (231)
----------------------------------------------------------------------------
                                                   $      (257) $      (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
During 2012, the Company recognized a gain of $1 million (December
31, 2011 - loss of $2 million) related to ineffectiveness arising
from cash flow hedges. 
Risk Management 
The Company uses derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures. The
se
financial instruments are entered into solely for hedging purposes
and are not used for speculative purposes. 
The estimated fair value of derivative financial instruments has been
determined based on appropriate internal valuation methodologies
and/or third party indications. Fair values determined using
valuation models require the use of assumptions concerning the amount
and timing of future cash flows and discount rates. In determining
these assumptions, the Company primarily relied on external,
readily-observable market inputs including quoted commodity prices
and volatility, interest rate yield curves, and foreign exchange
rates. The resulting fair value estimates may not necessarily be
indicative of the amounts that could be realized or settled in a
current market transaction and these differences may be material. 
The changes in estimated fair values of derivative financial
instruments included in the risk management asset (liability) were
recognized in the financial statements as follows: 


 
                                                  -------------
                                                    Year Ended   Year Ended
                                                       Dec 31,      Dec 31,
Asset (liability)                                         2012         2011
----------------------------------------------------------------------------
Balance - beginning of year                        $      (274) $      (485)
Net change in fair value of outstanding derivative
 financial instruments attributable to:
  Risk management activities                                42          128
  Foreign exchange                                         (53)          42
  Other comprehensive income                                28           41
----------------------------------------------------------------------------
Balance - end of year                                     (257)        (274)
Less: current portion                                       (4)         (43)
----------------------------------------------------------------------------
                                                   $      (253) $      (231)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

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


 
                             Three Months Ended            Year Ended
                        --------------------------  -------------
                              Dec 31        Dec 31         Dec 31   Dec 31
                                2012          2011           2012      2011
----------------------------------------------------------------------------
Net realized risk
 management (gain) loss  $        (8) $         20 $       162  $       101
Net unrealized risk
 management loss (gain)            8            58         (42)        (128)
----------------------------------------------------------------------------
                         $         -  $         78 $       120  $       (27)
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
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 December 31, 2012, the Company had the
following derivative financial instruments outstanding to manage its
commodity price risk:
Sales contracts 


 
                                                      Weighted average
                     Remaining term        Volume                price Index
----------------------------------------------------------------------------
Crude oil
Crude oil price
 collars (1)    Jan 2013 - Jun 2013  50,000 bbl/d US$80.00 - US$145.07 Brent
                Jan 2013 - Dec 2013  50,000 bbl/d US$80.00 - US$135.59 Brent
                Jan 2013 - Dec 2013  50,000 bbl/d  US$80.00 - US$97.73   WTI
                Jan 2013 - Dec 2013  50,000 bbl/d US$80.00 - US$110.34   WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to December 31, 2012, the Company entered into an additional
    50,000 bbl/d of US$80 - US$111.05 WTI collars for the period April to
    December 2013 and an additional 50,000 bbl/d of US$80 - US$132.18 Brent
    collars for the period July to December 2013.

 
During the fourth quarter of 2012, US$19 million of put option costs
were settled.
The Company's outstanding commodity derivative financial instruments
are expected to be settled monthly based on the applicable index
pricing for the respective contract month. 
Interest rate risk management 
The Company is exposed to interest rate price risk on its fixed rate
long-term debt and to interest rate cash flow risk on its floating
rate long-term debt. The Company periodically enters into interest
rate swap contracts to manage its fixed to floating interest rate mix
on long-term debt. The interest rate swap contracts require the
periodic exchange of payments without the exchange of the notional
principal amounts on which the payments are based. At December 31,
2012, the Company had no interest rate swap contracts outstanding. 
Foreign currency exchange rate risk management 
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated long-term debt
and working capital. The Company is also exposed to foreign currency
exchange rate risk on transactions conducted in other currencies in
its subsidiaries and in the carrying value of its foreign
subsidiaries. The Company periodically enters into cross currency
swap contracts and foreign currency forward contracts to manage known
currency exposure on US dollar denominated long-term debt and working
capital. The cross currency swap contracts require the periodic
exchange of payments with the exchange at maturity of notional
principal amounts on which the payments are based. At December 31,
2012, the Company had the following cross currency swap contracts
outstanding: 


 
                                              Exchange
                                                  rate   Interest   Interest
                    Remaining term   Amount   (US$/C$) rate (US$)  rate (C$)
----------------------------------------------------------------------------
Cross
 currency
Swaps          Jan 2013 - Aug 2016   US$250      1.116      6.00%      5.40%
               Jan 2013 - May 2017 US$1,100      1.170      5.70%      5.10%
               Jan 2013 - Nov 2021   US$500      1.022      3.45%      3.96%
               Jan 2013 - Mar 2038   US$550      1.170      6.25%      5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
All cross currency swap derivative financial instruments designated
as hedges at December 31, 2012, were classified as cash flow hedges. 
In addition to the cross currency swap contracts noted above, at
December 31, 2012, the Company had US$2,821 million of foreign
currency forward contracts outstanding, with terms of approximately
30 days or less. 
b) Credit Risk 
Credit risk is the risk that a party to a financial instrument will
cause a financial loss to the Company by failing to discharge an
obligation. 
Counterparty credit risk management 
The Company's accounts recei
vable 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
December 31, 2012, substantially all of the Company's accounts
receivable were due within normal trade terms. 
The Company is also exposed to possible losses in the event of
nonperformance by counterparties to derivative financial instruments;
however, the Company manages this credit risk by entering into
agreements with counterparties that are substantially all investment
grade financial institutions and other entities. At December 31,
2012, the Company had net risk management assets of $18 million with
specific counterparties related to derivative financial instruments
(December 31, 2011 - $nil). 
c) Liquidity Risk 
Liquidity risk is the risk that the Company will encounter difficulty
in meeting obligations associated with financial liabilities. 
Management of liquidity risk requires the Company to maintain
sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating activities,
available credit facilities, and access to debt capital markets, to
meet obligations as they become due. The Company believes it has
adequate bank credit facilities to provide liquidity to manage
fluctuations in the timing of the receipt and/or disbursement of
operating cash flows. 
The maturity dates for financial liabilities are as follows: 


 
                                           1 to less   2 to less
                               Less than        than        than
                                  1 year     2 years     5 years  Thereafter
----------------------------------------------------------------------------
Accounts payable             $       465 $         - $         - $         -
Accrued liabilities          $     2,273 $         - $         - $         -
Risk management              $         4 $        53 $       123 $        77
Other long-term liabilities  $        22 $        24 $        33 $         -
Long-term debt (1)           $       798 $       846 $     2,714 $     4,430
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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: 


 
                            2013    2014    2015    2016    2017  Thereafter
----------------------------------------------------------------------------
Product transportation
 and pipeline            $   231 $   218 $   204 $   135 $   117 $       788
Offshore equipment
 operating leases and
 offshore drilling       $   156 $   135 $   104 $    76 $    57 $        65
Office leases            $    33 $    34 $    32 $    33 $    35 $       262
Other                    $   173 $    95 $    43 $    10 $     2 $         7
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
In addition to the commitments disclosed above, the Company has
entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These
contracts can be cancelled by the Company upon notice without
penalty, subject to the costs incurred up to and in respect of the
cancellation. 
The Company is a defendant and plaintiff in a number of legal actions
arising in the normal course of business. In addition, the Company is
subject to certain contractor construction claims. The Company
believes that any liabilities that might arise pertaining to any such
matters would not have a material effect on its consolidated
financial position. 
15. SEGMENTED INFORMATION 


 
                                   Exploration and Production
                           North America                 North Sea
(millions of         Three Months                Three Months
 Canadian               Ended       Year Ended      Ended       Year Ended
 dollars,unaudited)     Dec 31        Dec 31        Dec 31        Dec 31
                    --------------------------------------------------------
                      2012   2011   2012   2011    2012  2011   2012   2011
----------------------------------------------------------------------------
Segmented product
 sales               3,006  3,163 11,607 11,806     215   317    928  1,224
Less: royalties       (277)  (482)(1,268)(1,538)      -    (1)    (2)    (3)
----------------------------------------------------------------------------
Segmented revenue    2,729  2,681 10,339 10,268     215   316    926  1,221
----------------------------------------------------------------------------
Segmented expenses
Production             557    516  2,165  1,933     100   103    402    412
Transportation and
 blending              735    575  2,735  2,301       2     3     10     13
Depletion,
 depreciation and
 amortization (note
 3)                    965    726  3,413  2,840      74    65    296    249
Asset retirement
 obligation
 accretion              21     17     85     70       7     9     27     33
Realized risk
 management
 activities             (8)    20    162    101       -     -      -      -
Horizon asset
 impairment
 provision               -      -      -      -       -     -      -      -
Insurance recovery -
 property damage
 (note 7)                -      -      -      -       -     -      -      -
Insurance recovery -
 business
 interruption (note
 7)                      -      -      -      -       -     -      -      -
Equity loss from
 jointly controlled
 entity                  -      -      -      -       -     -      -      -
----------------------------------------------------------------------------
Total segmented
 expenses            2,270  1,854  8,560  7,245     183   180    735    707
----------------------------------------------------------------------------
Segmented earnings
 (loss) before the
 following             459    827  1,779  3,023      32   136    191    514
----------------------------------------------------------------------------
Non-segmented
 expenses
Administration
Share-based
 compensation
Interest and other
 financing costs
Unrealized risk
 management
 activities
Foreign exchange
 loss (gain)
----------------------------------------------------------------------------
Total non-segmented
 expenses
----------------------------------------------------------------------------
Earnings before
 taxes
Current income tax
 expense
Deferred income tax
 (recovery) expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                   Exploration and Production
                                                   Total Exploration and
                          Offshore Africa                Production
(millions of         Three Months                Three Months
 Canadian               Ended       Year Ended      Ended       Year Ended
 dollars,unaudited)     Dec 31        Dec 31        Dec 31        Dec 31
                    --------------------------------------------------------
                      2012   2011   2012   2011   2012   2011   2012   2011
----------------------------------------------------------------------------
Segmented product
 sales                 158    308    773    946  3,379  3,788 13,308 13,976
Less: royalties        (53)   (46)  (199)  (114)  (330)  (529)(1,469)(1,655)
----------------------------------------------------------------------------
Segmented revenue      105    262    574    832  3,049  3,259 11,839 12,321
----------------------------------------------------------------------------
Segmented expenses
Production              39     66    163    186    696    685  2,730  2,531
Transportation and
 blending                -      -      1      1    737    578  2,746  2,315
Depletion,
 depreciation and
 amortization (note
 3)                     58     72    165    242  1,097    863  3,874  3,331
Asset retirement
 obligation
 accretion               2      2      7      7     30     28    119    110
Realized risk
 management
 activities              -      -      -      -     (8)    20    162    101
Horizon asset
 impairment
 provision               -      -      -      -      -      -      -      -
Insurance recovery -
 property damage
 (note 7)                -      -      -      -      -      -      -      -
Insurance recovery -
 business
 interruption (note
 7)                      -      -      -      -      -      -      -      -
Equity loss from
 jointly controlled
 entity                  -      -      -      -      -      -      -      -
----------------------------------------------------------------------------
Total segmented
 expenses               99    140    336    436  2,552  2,174  9,631  8,388
----------------------------------------------------------------------------
Segmented earnings
 (loss) before the
 following               6    122    238    396    497  1,085  2,208  3,933
----------------------------------------------------------------------------
Non-segmented
 expenses
Administration
Share-based
 compensation
Interest and other
 financing costs
Unrealized risk
 management
 activities
Foreign exchange
 loss (gain)
----------------------------------------------------------------------------
Total non-segmented
 expenses
----------------------------------------------------------------------------
Earnings before
 taxes
Current income tax
 expense
Deferred income tax
 (recovery) expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                        Oil Sands Mining and
                             Upgrading                    Midstream
(millions of         Three Months                Three Months
 Canadian               Ended       Year Ended       Ended      Year Ended
 dollars,unaudited)     Dec 31        Dec 31        Dec 31        Dec 31
                    --------------------------------------------------------
                      2012   2011   2012   2011    2012   2011   2012   2011
----------------------------------------------------------------------------
Segmented product
 sales                 675  1,005  2,871  1,521      26     22     93     88
Less: royalties        (29)   (41)  (137)   (60)      -      -      -      -
----------------------------------------------------------------------------
Segmented revenue      646    964  2,734  1,461      26     22     93     88
----------------------------------------------------------------------------
Segmented expenses
Production             372    344  1,504  1,127       8      7     29     26
Transportation and
 blending               15     16     61     62       -      -      -      -
Depletion,
 depreciation and
 amortization (note
 3)                    114    133    447    266       2      2      7      7
Asset retirement
 obligation
 accretion               8      5     32     20       -      -      -      -
Realized risk
 management
 activities              -      -      -      -       -      -      -      -
Horizon asset
 impairment
 provision               -      -      -    396       -      -      -      -
Insurance recovery -
 property damage
 (note 7)                -      3      -   (393)      -      -      -      -
Insurance recovery -
 business
 interruption (note
 7)                      -    (16)     -   (333)      -      -      -      -
Equity loss from
 jointly controlled
 entity                  -      -      -      -       3      -      9      -
----------------------------------------------------------------------------
Total segmented
 expenses              509    485  2,044  1,145      13      9     45     33
----------------------------------------------------------------------------
Segmented earnings
 (loss) before the
 following             137    479    690    316      13     13     48     55
----------------------------------------------------------------------------
Non-segmented
 expenses
Administration
Share-based
 compensation
Interest and other
 financing costs
Unrealized risk
 management
 activities
Foreign exchange
 loss (gain)
----------------------------------------------------------------------------
Total non-segmented
 expenses
----------------------------------------------------------------------------
Earnings before
 taxes
Current income tax
 expense
Deferred income tax
 (recovery) expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
 
 
                     Inter-segment elimination
                             and other                     Total
(millions of         Three Months                Three Months
 Canadian               Ended       Year Ended      Ended       Year Ended
 dollars,unaudited)     Dec 31        Dec 31        Dec 31        Dec 31
                    --------------------------------------------------------
                      2012   2011   2012   2011   2012   2011   2012   2011
----------------------------------------------------------------------------
Segmented product
 sales                 (21)   (27)   (77)   (78) 4,059  4,788 16,195 15,507
Less: royalties          -      -      -      -   (359)  (570)(1,606)(1,715)
----------------------------------------------------------------------------
Segmented revenue      (21)   (27)   (77)   (78) 3,700  4,218 14,589 13,792
----------------------------------------------------------------------------
Segmented expenses
Production              (4)    (2)   (14)   (13) 1,072  1,034  4,249  3,671
Transportation and
 blending              (14)   (12)   (55)   (50)   738    582  2,752  2,327
Depletion,
 depreciation and
 amortization (note
 3)                      -      -      -      -  1,213    998  4,328  3,604
Asset retirement
 obligation
 accretion               -      -      -      -     38     33    151    130
Realized risk
 management
 activities              -      -      -      -     (8)    20    162    101
Horizon asset
 impairment
 provision               -      -      -      -      -      -      -    396
Insurance recovery -
 property damage
 (note 7)                -      -      -      -      -      3      -   (393)
Insurance recovery -
 business
 interruption (note
 7)                      -      -      -      -      -    (16)     -   (333)
Equity loss from
 jointly controlled
 entity                  -      -      -      -      3      -      9      -
----------------------------------------------------------------------------
Total segmented
 expenses              (18)   (14)   (69)   (63) 3,056  2,654 11,651  9,503
----------------------------------------------------------------------------
Segmented earnings
 (loss) before the
 following              (3)   (13)    (8)   (15)   644  1,564  2,938  4,289
----------------------------------------------------------------------------
Non-segmented
 expenses
Administration                                      64     47    270    235
Share-based
 compensation                                      (41)   207   (214)  (102)
Interest and other
 financing costs                                    83     83    364    373
Unrealized risk
 management
 activities                                          8     58    (42)  (128)
Foreign exchange
 loss (gain)                                        58   (106)   (49)     1
----------------------------------------------------------------------------
Total non-segmented
 expenses                                          172    289    329    379
----------------------------------------------------------------------------
Earnings before
 taxes                                             472  1,275  2,609  3,910
Current income tax
 expense                                           189    299    747    860
Deferred income tax
 (recovery) expense                                (69)   144    (30)   407
----------------------------------------------------------------------------
Net earnings                                       352    832  1,892  2,643
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
Capital Expenditures (1) 


 
                                              Year Ended
                        ----------------------------------------------------
                                             Dec 31, 2012
----------------------------------------------------------------------------
                                                Non cash
                                      Net  and fair value       Capitalized
                             expenditures       changes(2)            costs
----------------------------------------------------------------------------
 
Exploration and
 evaluation assets
Exploration and
 Production
 North America           $            295 $          (173) $            122
 North Sea                              -               -                 -
 Offshore Africa                       14               -                14
----------------------------------------------------------------------------
                         $            309 $          (173) $            136
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
Property, plant and
 equipment
Exploration and
 Production
 North America           $          3,831 $           373  $          4,204
 North Sea                            254             263               517
 Offshore Africa                       50              17                67
----------------------------------------------------------------------------
                                    4,135             653             4,788
Oil Sands Mining and
 Upgrading (3) (4)                  1,610             142             1,752
Midstream                              14               -                14
Head office                            36               -                36
----------------------------------------------------------------------------
                         $          5,795 $           795  $          6,590
----------------------------------------------------------------------------
----------------------------------------------------------------------------
 
                                            Year Ended
                        ---------------------------------------------------
                                            Dec 31, 2011
---------------------------------------------------------------------------
                                             Non cash and
                                      Net      fair value      Capitalized
                             expenditures      changes(2)            costs
---------------------------------------------------------------------------
 
Exploration and
 evaluation assets
Exploration and
 Production
 North America           $            309 $          (233) $            76
 North Sea                              1              (6)              (5)
 Offshore Africa                        2               -                2
---------------------------------------------------------------------------
                         $            312 $          (239) $            73
---------------------------------------------------------------------------
---------------------------------------------------------------------------
 
Property, plant and
 equipment
Exploration and
 Production
 North America           $          4,427 $           832  $         5,259
 North Sea                            226              15              241
 Offshore Africa                       31              16               47
---------------------------------------------------------------------------
                                    4,684             863            5,547
Oil Sands Mining and
 Upgrading (3) (4)                  1,182            (140)           1,042
Midstream                               5               2                7
Head office                            18               -               18
---------------------------------------------------------------------------
                         $          5,889 $           725  $         6,614
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(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.
(4) During the first quarter of 2011, the Company derecognized certain
    property, plant and equipment related to the coker fire at Horizon in
    the amount of $411 million. This amount was included in non cash and
    fair value changes.

 
Segmented Assets 


 
                                                          Total Assets
                                                  --------------------------
                                                         Dec 31       Dec 31
                                                           2012         2011
----------------------------------------------------------------------------
Exploration and Production
  North America                                    $     29,012 $     28,233
  North Sea                                               1,993        1,809
  Offshore Africa                                           924        1,070
  Other                                                      36           23
Oil Sands Mining and Upgrading                           16,291       15,433
Midstream                                                   636          642
Head office                                                  88           68
----------------------------------------------------------------------------
                                                   $     48,980 $     47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------

 
SUPPLEMENTARY INFORMATION 
INTEREST COVERAGE RATIOS 
The following financial ratios are provided in connection with the
Company's continuous offering of medium-term notes pursuant to the
short form prospectus dated October 2011. These ratios are based on
the Company's interim consolidated financial statements that are
prepared in accordance with accounting principles generally accepted
in Canada. 


 
Interest coverage ratios for the twelve month period ended December
 31, 2012:
----------------------------------------------------------------------------
Interest coverage (times)
  Net earnings (1)                                                      6.4x
  Cash flow from operations (2)                                        15.3x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net earnings plus income taxes and interest expense excluding current
    and deferred PRT expense and other taxes; divided by the sum of interest
    expense and capitalized interest.
(2) Cash flow from operations plus current income taxes and interest expense
    excluding current PRT expense and other taxes; divided by the sum of
    interest expense and capitalized interest.

 
CONFERENCE CALL 
A conference call will be held at 9:00 a.m. Mountain Time, 11:00 a.m.
Eastern Time on Thursday, March 7, 2013. The North American
conference call number is 1-877-240-9772 and the outside North
American conference call number is 001-416-340-8527. Please call in
about 10 minutes before the starting time in order to be patched into
the call. 
A taped rebroadcast will be available until 6:00 p.m. Mountain Time,
Thursday, March 14, 2013. To access the rebroadcast in North America,
dial 1-800-408-3053. Those outside of North America, dial
001-905-694-9451. The pass code to use is 6854115. 
WEBCAST 
The conference call will also be broadcast live on the internet and
may be accessed through the Canadian Natural website at www.cnrl.com.
Contacts:
John G. Langille
Vice-Chairman 
Steve W. Laut
President 
Corey B. Bieber
Vice-President, Finance & Investor Relations 
Canadian Natural Resources Limited
2500, 855 2nd Street S.W.
Calgary, Alberta, T2P 4J8 Canada
Phone: (403) 514-7777
Fax: (403) 514-7888 (FAX)
ir@cnrl.com
www.cnrl.com