Canadian Natural Resources Limited Announces 2013 Fourth Quarter
and Year End Results
CALGARY, ALBERTA--(Marketwired - Mar 6, 2014) - Commenting on
fourth quarter and year end results, Steve Laut, President of
Canadian Natural (TSX: CNQ)(NYSE: CNQ) stated, "2013 was a solid
year for Canadian Natural as we achieved significant progress in
our transition to longer life, low decline assets. We achieved
record cash flow of approximately $7.5 billion in 2013 and we grew
our total liquids production by 6% to approximately 478,000 barrels
per day, with total production of 671,162 barrels of oil equivalent
per day. Additionally, we increased total Company Gross proved plus
probable reserves to 7.99 billion BOE, replacing 143% of
production, with a proved plus probable reserve life index of
approximately 35 years.
During 2013, Canadian Natural continued to effectively execute
our strategy to transform our asset base to longer life, low
decline production. The Kirby South SAGD project achieved first
steam injection ahead of schedule and on budget during the third
quarter of 2013. Production is targeted to ramp up to 40,000
barrels per day of crude oil by the end of 2014. This is an
important step in the development of our in situ oil sands
reserves. Expansion of Horizon to 250,000 barrels per day is
tracking 10% below cost estimates, with Phase 2A targeted to add
12,000 barrels per day of additional SCO production capacity in
2014, ahead of the original 2015 plan. Horizon also achieved a step
change in reliability this year as a result of several initiatives
including the successful completion of the first major planned
turnaround. Horizon averaged over 100,000 barrels per day of high
quality synthetic crude oil during 2013, an increase of 17% over
the 2012 average volumes and within the original 2013 budgeted
guidance.
In 2013 production growth was solid, driving our record cash
flow. The facilities at our leading edge Pelican Lake polymer flood
were expanded in 2013 and associated crude oil production increased
12% year over year. Canadian Natural had 7% production growth in
North American light crude oil and NGLs and 9% production growth in
primary heavy crude oil in 2013 over 2012. We maintain an enviable
position with our vast and balanced asset base; and we target all
aspects of the business to generate free cash flow while maximizing
returns to our shareholders."
Canadian Natural's Chief Financial Officer, Corey Bieber,
continued, "Our record cash flow of approximately $7.5 billion was
due to strong operating performance overall and a healthy price
environment, which contributed to a 24% increase in cash flow over
the comparable period in 2012. We exited the year with a strong
balance sheet, with debt to book capitalization of 27% and debt to
EBITDA of 1.1 times.
As a result of the Company's continued strength and successful
execution of our proven effective strategy, the Company's Board of
Directors, as part of its annual review of dividend payment levels
concurrently with the approval of the Company's year-end financial
statements, have increased the quarterly dividend to $0.225 per
share. This increase is in addition to the aggregate quarterly
dividend increase of 90% announced during 2013. In addition, as
part of our Normal Course Issuer Bid in 2013, we purchased 10.2
million common shares for cancellation.
Our balance sheet allows us the flexibility to continue to
develop the assets with the highest returns while we generate
substantial and growing free cash flow which can be allocated to
resource development, sustainable dividends, share purchases,
opportunistic acquisitions, and debt repayment."
QUARTERLY AND ANNUAL HIGHLIGHTS
Three Months Ended Year Ended
-----------------------------------------------
($ Millions, except per Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
common share amounts) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Net earnings $ 413 $ 1,168 $ 352 $ 2,270 $ 1,892
Per common share - basic $ 0.38 $ 1.07 $ 0.32 $ 2.08 $ 1.72
- diluted $ 0.38 $ 1.07 $ 0.32 $ 2.08 $ 1.72
Adjusted net earnings from
operations (1) $ 563 $ 1,009 $ 359 $ 2,435 $ 1,618
Per common share - basic $ 0.52 $ 0.93 $ 0.33 $ 2.24 $ 1.48
- diluted $ 0.52 $ 0.93 $ 0.33 $ 2.23 $ 1.47
Cash flow from operations (2) $ 1,782 $ 2,454 $ 1,548 $ 7,477 $ 6,013
Per common share - basic $ 1.64 $ 2.26 $ 1.41 $ 6.87 $ 5.48
- diluted $ 1.64 $ 2.26 $ 1.41 $ 6.86 $ 5.47
Capital expenditures, net of
dispositions $ 2,091 $ 1,655 $ 1,767 $ 7,274 $ 6,308
Daily production, before
royalties
Natural gas (MMcf/d) 1,195 1,163 1,134 1,158 1,220
Crude oil and NGLs (bbl/d) 478,038 509,182 469,964 478,240 451,378
Equivalent production
(BOE/d) (3) 677,242 702,938 658,973 671,162 654,665
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(1) Adjusted net earnings from operations is a non-GAAP measure
that the Company utilizes to evaluate its performance. The
derivation of this measure is discussed in the Management's
Discussion and Analysis ("MD&A").
(2) Cash flow from operations is a non-GAAP measure that the
Company considers key as it demonstrates the Company's ability to
fund capital reinvestment and debt repayment. The derivation of
this measure is discussed in the MD&A.
(3) A barrel of oil equivalent ("BOE") is derived by converting
six thousand cubic feet ("Mcf") of natural gas to one barrel
("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be
misleading, particularly if used in isolation, since the 6 Mcf:1
bbl ratio is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead. In comparing the value ratio
using current crude oil prices relative to natural gas prices, the
6 Mcf:1 bbl conversion ratio may be misleading as an indication of
value.
Annual
- Total overall production for the year averaged 671,162 BOE/d
representing an increase of 3% from 2012. Canadian Natural's
production volumes were driven by greater reliability of Horizon
Oil Sands ("Horizon") operations, successful light and primary
heavy crude oil drilling programs and strong production at Pelican
Lake, and offset by planned production declines in natural gas.
- Total crude oil and NGLs production for the year averaged
478,240 bbl/d, an increase of 6% from 2012. Crude oil production
increased in 2013 as follows:
-- 17% annual increase in Horizon production,
-- 12% annual increase in Pelican Lake production,
-- 9% annual increase in primary heavy crude oil production,
and,
-- 7% annual increase in North America light crude oil and NGLs
production.
- Total natural gas production for the year averaged 1,158
MMcf/d and was minimized to a 5% decrease from 2012 due to
liquids-rich natural gas development at Septimus and minor
acquisitions throughout the year. The decrease reflects expected
production declines and Canadian Natural's strategic decision to
allocate capital to higher return crude oil projects.
- Canadian Natural realized record cash flow from operations in
2013 of approximately $7.5 billion. This is a 24% increase in cash
flow compared to approximately $6.0 billion in 2012. The increase
in cash flow was primarily due to higher overall crude oil volumes
and higher realized synthetic crude oil ("SCO") and natural gas
prices.
- Adjusted net earnings from operations increased to $2.4
billion in 2013 compared to $1.6 billion in 2012. Changes in
adjusted net earnings reflect the changes in cash flow from
operations partially offset by 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 highlights are based on the Company's
reserves using forecast prices and costs as at December 31,
2013:
-- North America E&P Company Gross proved crude oil, bitumen
and NGLs reserves increased 8% to 1.89 billion barrels. Company
Gross proved natural gas reserves increased 4% to 4.16 Tcf. Total
proved BOE increased 7% to 2.58 billion barrels, with a reserve
replacement ratio of 188%.
-- North America E&P Company Gross proved plus probable
crude oil, bitumen and NGLs reserves increased 4% to 3.21 billion
barrels. Company Gross proved plus probable natural gas reserves
increased 6% to 5.88 Tcf. Total proved plus probable BOE increased
4% to 4.19 billion barrels, with a reserve replacement ratio of
191%.
-- Thermal oil sands (bitumen) Company Gross proved reserves
increased 9% to 1.16 billion 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 reserve additions and revisions were 126 million
barrels. Total proved plus probable bitumen reserves increased 2%
to 2.17 billion barrels.
-- Canadian Natural total Company Gross proved crude oil, SCO,
bitumen and NGLs reserves increased 2% to 4.42 billion barrels.
Company Gross proved natural gas reserves increased 4% to 4.31 Tcf.
Total proved reserves increased 2% to 5.14 billion BOE, resulting
in a reserve life index of 22.8 years.
-- Canadian Natural total Company Gross proved reserves
increased by 364 million BOE through additions and revisions,
resulting in a proved reserve replacement ratio of 149%.
-- Canadian Natural total Company Gross proved plus probable
crude oil, SCO, bitumen and NGLs reserves increased 1% to 6.97
billion barrels. Company Gross proved plus probable natural gas
reserves increased 6% to 6.11 Tcf. Total proved plus probable
reserves increased 1% to 7.99 billion BOE resulting in a reserve
life index of 35.4 years.
-- Canadian Natural total Company Gross proved plus probable
reserves increased by 350 million BOE through additions and
revisions, resulting in a proved plus probable reserve replacement
ratio of 143%.
- Total net exploration and production reserve replacement
expenditures totaled approximately $4.24 billion in 2013, including
acquisitions and excluding Horizon. Horizon project capital
(including capitalized interest, share-based compensation and
other) totaled approximately $2.21 billion and sustaining and
turnaround capital totaled approximately $378 million.
- Subsequent to Q4/13, the Company announced an agreement to
acquire certain Canadian assets of Devon Canada ("Devon Assets")
for total cash consideration of approximately $3.125 billion,
effective January 1, 2014, with a targeted closing date of April 1,
2014. The Devon Assets are all located in Western Canada in areas
adjacent or proximal to Canadian Natural's current operations and
are high quality, concentrated liquids-rich natural gas weighted
assets, with additional light crude oil exposure. Devon Assets also
include associated key strategic facilities, a royalty revenue
stream and undeveloped land. The acquired Company Gross proved
reserves, excluding the royalty land position, are 272.2 million
BOE, as evaluated by an Independent Qualified Reserves Evaluator
retained by Devon, as at December 31, 2013 using forecast prices
and costs.
Fourth Quarter
- Total crude oil and NGLs production was 478,038 bbl/d for
Q4/13. Q4/13 crude oil and NGLs production volumes increased 2%
from Q4/12 largely as a result of safe, steady and reliable
production at Horizon, production growth at Pelican Lake and
increased NGLs production. Q4/13 crude oil and NGLs production
volumes decreased 6% from Q3/13 as a result of lower thermal
production, as expected, and lower primary heavy crude oil
production. This decrease was primarily due to the strategic
temporary reduction of primary heavy crude oil production in
response to wider WCS heavy differentials and the impact on primary
heavy crude oil production volumes at Woodenhouse due to the
temporary loss of a third party fuel gas pipeline.
- Total natural gas production was 1,195 MMcf/d in Q4/13, an
increase of 5% and 3% from Q4/12 and Q3/13 respectively. The
increase in production is largely due to the concentrated
liquids-rich Montney natural gas drilling program at Septimus, as
well as minor property acquisitions.
- Canadian Natural generated quarterly cash flow from operations
of $1.78 billion compared with $1.55 billion in Q4/12 and $2.45
billion in Q3/13. The increase in cash flow from Q4/12 was due to
higher SCO sales volumes, higher crude oil and NGLs sales volumes
in Offshore Africa, and the impact of a weaker Canadian dollar
relative to the US dollar, partially offset by lower North America
crude oil and NGLs sales volumes. The decrease in cash flow from
Q3/13 was due to lower realized SCO and North America crude oil and
NGLs prices and expected lower crude oil and NGLs sales volumes in
North America. These factors were partially offset by higher crude
oil and NGLs sales volumes in Offshore Africa.
- Adjusted net earnings from operations for Q4/13 were $563
million, compared to adjusted net earnings of $359 million in Q4/12
and $1,009 million Q3/13. Changes in adjusted net earnings reflect
the changes in cash flow from operations.
Operational and Financial
- In 2013 North America light oil and NGLs production volumes
increased 7% from 2012.
-- The plant expansion at Septimus, the Company's premium
liquids-rich natural gas Montney play, was completed during Q3/13.
During the first week of September 2013, the newly expanded gas
plant reached its production capacity of 125 MMcf/d and
approximately 12,200 bbl/d of liquids with the completion of new
wells. With high liquids yields and low operating costs of
approximately $0.22/Mcfe, Septimus continues to generate excellent
returns and significant free cash flow while maximizing the
utilization of the plant capacity.
-- In Q3/13, Canadian Natural completed the acquisition of
Barrick Energy Inc. for approximately $173 million. The production
and undeveloped land base is complementary to Canadian Natural's
existing assets and is concentrated in light oil weighted assets
with strong netbacks and a long reserve life. This acquisition
added approximately 4,200 bbl/d of light crude oil and NGLs and 4
MMcf/d of natural gas production. These assets have been integrated
into the Company's operations and optimization opportunities are
underway.
- Canadian Natural's primary heavy crude oil continued to
provide strong netbacks and amongst the highest returns on capital
in the Company's portfolio of diverse and balanced assets. Primary
heavy crude oil operations achieved annual production volumes of
approximately 136,000 bbl/d, representing an average annual
production growth of 9% over 2012. The Q4/13 primary heavy crude
oil production volumes were approximately 135,000 bbl/d, a 3%
increase from Q4/12 and a 4% decrease from Q3/13 levels. The
decrease in production levels from the previous quarter was largely
due to the strategic temporary reduction of production levels by
approximately 10,500 bbl/d of primary heavy crude oil production
volumes for approximately 30 days in response to wider WCS heavy
differentials.
- WCS differentials to WTI widened to 40% in December. To
partially mitigate the cash flow impact from temporarily wider
differentials, the Company strategically curtailed production
levels by approximately 10,500 bbl/d of primary heavy crude oil
production volumes for approximately 30 days. Primary heavy crude
oil production volumes were deferred to January and February, when
differentials narrowed to 31% and 19% respectively.
- Pelican Lake achieved record quarterly crude oil production of
approximately 46,000 bbl/d in Q4/13, a 27% increase from Q4/12 and
a 1% increase from Q3/13 levels. This is the fourth consecutive
quarter of production increases, which reflects Canadian Natural's
continued success in implementing polymer flooding technology at
this property. Pelican Lake's industry leading operating costs of
$9.25/bbl in Q4/13 represent a 28% decrease from Q4/12 levels. The
increasing polymer flood production response combined with
continued optimization and effective and efficient operations have
driven cost improvements, resulting in increasing free cash flow
generation.
- Kirby South, a 100% owned and operated SAGD project, was
completed during Q3/13, on budget, at a cost of approximately
$30,000 per flowing barrel. At the end of Q4/13, steam was being
circulated in 36 well pairs on 6 pads to initiate the SAGD process.
Subsequent to Q4/13, 15 well pairs have been converted to SAGD
production as planned. The wells at Kirby South are responding as
expected and production is targeted to grow to 40,000 bbl/d in
Q4/14. All evaporators, steam generators and oil treating vessels
are in service and the first shipment of crude oil produced was
delivered during Q4/13 with production averaging 1,500 bbl/d for
the quarter. Production ramp up continues as expected, with current
production of approximately 7,000 bbl/d.
- Horizon achieved strong and reliable operating performance for
all of 2013. Horizon SCO production averaged approximately 112,000
bbl/d in the second half of 2013 upon the completion of the first
major turnaround. The Q4/13 production volumes of 112,273 bbl/d
represent a 35% increase from Q4/12 levels, indicating a step
change in safe, steady and reliable production at Horizon. Canadian
Natural expects continued strong operating performance, and for the
first two months of 2014 production has averaged approximately
111,000 bbl/d. Horizon production is targeted to increase by 11% in
2014 from 2013 levels as a result of the continued focus on
effective and efficient operations.
- During 2013, the Company disposed of a 50% interest in its
exploration right in South Africa, for a net cash consideration of
US$255 million, including a recovery of US$14 million of past
incurred costs, resulting in an after-tax gain on sale of
exploration and evaluation property of $166 million. In the event
that a commercial crude oil or natural gas discovery occurs on this
exploration right, resulting in the exploration right being
converted into a production right, an additional cash payment would
be due to the Company at such time, amounting to US$450 million for
a commercial crude oil discovery and US$120 million for a
commercial natural gas discovery. Long lead equipment has been
ordered and the operator is targeting to drill the first
exploration well in Q3/14.
- For the year ended December 31, 2013, Canadian Natural
purchased for cancellation under its Normal Course Issuer Bid
10,164,800 common shares at a weighted average price of $31.46 per
common share. Subsequent to December 31, 2013, to date in 2014 the
Company has purchased for cancellation 1,475,000 common shares at a
weighted average price of $35.85 per common share.
- As a result of the Company's continued strength and successful
execution of its proven and effective strategy, Canadian Natural's
Board of Directors has increased the quarterly cash dividend on
common shares to C$0.225 per share payable on April 1, 2014. This
increase is in addition to the aggregate quarterly dividend
increase of 90% announced during 2013 and represents a 13% increase
over the previous quarterly dividend. This is the fourteenth
consecutive year of dividend increases since the Company first paid
a dividend in 2001, and a compound annual growth rate of 34% from
2009 when Horizon first commenced production. This dividend
reflects the continued strong operational results of the Company
and the successful execution to date on the thermal development
program and Horizon Phase 2/3 development, both in terms of
construction accomplished and cost performance to date and the
amount of future contracts that have been awarded.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural
focuses its activities in core regions where the Company owns a
substantial land base and associated infrastructure. Land
inventories are maintained to enable continuous exploitation of
play types and geological trends, greatly reducing overall
exploration risk. By owning and operating associated
infrastructure, the Company is able to maximize utilization of its
production facilities, thereby increasing control over production
costs. Furthermore, the Company maintains large project inventories
and production diversification among each of the commodities it
produces; light and medium crude oil, primary heavy crude oil,
Pelican Lake heavy crude oil, bitumen and SCO (herein collectively
referred to as "crude oil"), natural gas and NGLs. A large
diversified project portfolio enables the effective allocation of
capital to higher return opportunities.
OPERATIONS REVIEW
Activity by core region
Net unproved
property
as at Drilling activity
Dec 31, 2013 year ended
(thousands of net Dec 31, 2013
acres)(1) (net wells)(2)
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North America
Northeast British Columbia 2,956 31.4
Northwest Alberta 2,454 60.3
Northern Plains 7,131 913.3
Southern Plains 1,128 31.0
Southeast Saskatchewan 106 23.5
Thermal In Situ Oil Sands 838 280.0
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14,613 1,339.5
Oil Sands Mining and Upgrading 59 234.0
North Sea 110 1.0
Offshore Africa 2,467 0.0
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17,249 1,574.5
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(1) Unproved property 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
----------------------------------------
2013 2012
Gross Net Gross Net
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Crude oil 1,180 1,117 1,255 1,203
Natural gas 60 44 42 35
Dry 31 30 34 33
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Subtotal 1,271 1,191 1,331 1,271
Stratigraphic test / service wells 384 384 728 727
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Total 1,655 1,575 2,059 1,998
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Success rate (excluding
stratigraphic test / service wells) 97% 97%
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North America Exploration and Production
Crude oil and NGLs - excluding Thermal In Situ Oil Sands
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
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Crude oil and NGLs
production (bbl/d) 254,162 256,329 230,621 247,196 227,351
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Net wells targeting crude
oil 299 294 275 1,000 1,075
Net successful wells
drilled 289 287 256 974 1,042
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Success rate 97% 98% 93% 97% 97%
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- North America crude oil and NGLs production averaged 247,196
bbl/d for the year, an increase of 9% from 2012 levels. The
increase was largely driven by successful light and primary heavy
crude oil drilling programs, strong performance at Pelican Lake and
acquisitions.
- North America crude oil and NGLs production for Q4/13 was
254,162 bbl/d. Q4/13 crude oil and NGLs production volumes
increased 10% from Q4/12 as a result of strong performance in light
oil, NGLs, Pelican Lake and primary heavy crude oil production.
Crude oil and NGLs production volumes decreased 1% from Q3/13
levels, as a result of the strategic temporary reduction of
approximately 10,500 bbl/d of primary heavy crude oil production
volumes for approximately 30 days in response to wider WCS heavy
differentials.
- Woodenhouse returned to full production rates upon the
restoration of third party fuel gas supply on November 21, 2013,
with December primary heavy crude oil production volumes
approaching 16,000 bbl/d. Fuel gas supply to the Woodenhouse
operation was interrupted for a period of time as a result of a
third party fuel pipeline issue which resulted in a reduction of
production volumes by approximately 1,200 bbl/d, on average, during
Q4/13, as the Company had to acquire an alternative fuel source to
substantially mitigate the disruption.
- Canadian Natural drilled 259 net primary heavy crude oil wells
in Q4/13, completing an effective and efficient annual drilling
program of 859 net primary heavy crude oil wells during 2013. The
Company will continue the drilling program in 2014, leveraging
drilling efficiencies, with the target to drill 898 net primary
heavy crude oil wells. Canadian Natural's primary heavy crude oil
continues to provide strong netbacks and a high return on capital
in the Company's portfolio of diverse and balanced assets.
- Pelican Lake achieved record quarterly heavy crude oil
production of approximately 46,000 bbl/d in Q4/13, a 27% increase
from Q4/12 and a 1% increase from Q3/13 levels. This is the fourth
consecutive quarter of production increases, which reflects
Canadian Natural's continued success in implementing polymer
flooding technology at this property. Twelve net horizontal
production wells were drilled during the quarter and 17 net
horizontal production wells are targeted to be drilled in 2014.
Pelican Lake's industry leading operating costs of $9.25/bbl in
Q4/13 represent a 28% decrease in operating costs from Q4/12. The
increasing polymer flood production response combined with
continued optimization and effective and efficient operations have
driven cost improvements, resulting in increasing free cash flow
generation.
- North America light crude oil and NGLs achieved record
quarterly production of approximately 73,400 bbl/d in Q4/13.
Production increased 4% from Q3/13, partially as a result of
increased NGLs production associated with the Septimus project
expansion and minor property acquisitions. The Company drilled 28
net light crude oil wells in Q4/13. Canadian Natural's light crude
oil drilling program will continue to utilize and advance
horizontal multi-frac well technology to access new reserves in
pools across the Company's land base.
Thermal In Situ Oil Sands
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
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Bitumen production (bbl/d) 78,069 109,200 121,362 96,503 99,478
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Net wells targeting
bitumen 38 47 38 145 161
Net successful wells
drilled 35 47 38 142 161
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Success rate 92% 100% 100% 98% 100%
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- Average annual thermal in situ production for 2013 was
approximately 97,000 bbl/d representing a decrease of 3% from 2012.
Q4/13 thermal in situ production volumes were approximately 78,000
bbl/d due to the timing of steaming and production cycles and
steaming restrictions.
- During Q2/13, bitumen emulsion was discovered at surface at 4
separate locations in the Company's Primrose development area, 3 at
Primrose East and 1 at Primrose South. Canadian Natural continues
to work with Alberta Environment and Sustainable Resource
Development ("AESRD") on an effective and efficient clean-up.
Cleanup of the 3 Primrose East sites is complete and the Primrose
South site cleanup is targeted to be completed in Q1/14.
- The causation review of the bitumen emulsion seepage is
progressing well. The significant amount of data collected to date
indicates the cause of the bitumen emulsion seepage is the
mechanical failures of wellbores. No data collected to date
supports any other potential failure mechanisms. The method to
prevent seepages for all potential failure mechanisms has been
developed and includes the remediation of legacy wellbores,
modified steaming strategies, enhanced monitoring techniques and
proactive response strategies.
- Canadian Natural continues to work with the Alberta Energy
Regulator ("AER") on the causation review of the bitumen emulsion
seepage. The Company's near term steaming plan at Primrose has been
modified as a result of the seepages, with steaming being reduced
in certain areas until the causation review with the AER is
complete. Canadian Natural believes that reserves recovered from
the Primrose area over its life cycle will be substantially
unchanged and production guidance for 2014 also remains
unchanged.
- Kirby South, a 100% owned and operated SAGD project, was
completed during Q3/13, on budget, at a cost of approximately
$30,000 per flowing barrel. At the end of Q4/13, steam was being
circulated in 36 well pairs on 6 pads to initiate the SAGD process.
Subsequent to Q4/13, 15 well pairs have been converted to SAGD
production as planned. The wells at Kirby South are responding as
expected and production is targeted to grow to 40,000 bbl/d in
Q4/14. All evaporators, steam generators and oil treating vessels
are in service and the first shipment of crude oil produced was
delivered during Q4/13 with production averaging 1,500 bbl/d for
the quarter. Production ramp up continues as expected, with current
production of approximately 7,000 bbl/d.
- The Kirby North Phase 1 project is targeted for Board
sanctioning in mid 2014. Detailed engineering is progressing and,
currently, is approximately 97% complete.
- Kirby South and Kirby North Phase 1 will contribute to a
staged expansion plan for the greater Kirby area. The Company
targets to increase Kirby area production volumes, over time, to
approximately 140,000 bbl/d. Canadian Natural's current overall
thermal in situ development plan targets to increase facility
capacity from current levels to approximately 510,000 bbl/d in
staged increments over the next 15 years.
- Planned drilling activity for Q1/14 includes 8 net thermal in
situ (bitumen) wells, excluding strat and service wells.
Natural Gas
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Natural gas production
(MMcf/d) 1,165 1,136 1,113 1,130 1,198
----------------------------------------------------------------------------
Net wells targeting
natural gas 11 10 3 45 35
Net successful wells
drilled 11 10 3 44 35
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Success rate 100% 100% 100% 98% 100%
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- North America natural gas production averaged 1,130 MMcf/d for
the year, and was minimized to a 6% decrease from 2012, due to
liquids-rich development at Septimus and minor acquisitions
throughout the year. The decrease in production levels reflects
natural production declines and Canadian Natural's strategic
decision to allocate capital to higher return crude oil projects.
During Q4/13 natural gas production averaged 1,165 MMcf/d, a 5% and
3% increase from Q4/12 and Q3/13 levels respectively. The increase
in production from last quarter was largely driven by liquids-rich
Septimus production.
- The plant expansion at Septimus, the Company's premium
liquids-rich natural gas Montney play, was completed during Q3/13.
During the first week of September 2013, the newly expanded gas
plant reached its production capacity of 125 MMcf/d and
approximately 12,200 bbl/d of liquids with the completion of new
wells. With high liquids yields and low operating costs of
approximately $0.22/Mcfe, Septimus continues to generate excellent
returns and significant free cash flow while maximizing the
utilization of the plant capacity in 2014.
International Exploration and Production
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil production
(bbl/d)
North Sea 20,155 15,522 19,140 18,334 19,824
Offshore Africa 13,379 16,172 15,762 15,923 18,648
----------------------------------------------------------------------------
Natural gas production
(MMcf/d)
North Sea 7 4 1 4 2
Offshore Africa 23 23 20 24 20
----------------------------------------------------------------------------
Net wells targeting crude
oil - - - 1.0 -
Net successful wells
drilled - - - 1.0 -
----------------------------------------------------------------------------
Success rate - - - 100% -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- International crude oil production averaged 33,534 bbl/d
during the quarter, a 6% increase from Q3/13 levels. This increase
was primarily as a result of the successful completion of planned
turnarounds in the North Sea, offset by decreased Offshore Africa
crude oil production in the quarter due to a temporary shut in of
the Baobab field in December 2013 as a result of a mooring line
failure on the Floating Production Storage and Offloading ("FPSO")
vessel. Production in the Baobab field was temporarily reinstated
in late January 2014, with final repairs targeted for March
2014.
- During Q4/13 the Company contracted a drilling rig for a 6
well (3.5 net) drilling program at the Baobab field in Côte
d'Ivoire. This rig is expected to arrive no later than Q1/15 to
commence the program, which is targeted to add 11,000 BOE/d of net
production when complete.
- Canadian Natural is in the process of obtaining a drilling rig
to undertake the light crude oil infill drilling program at Espoir,
Cote d'Ivoire. The development of Espoir is now targeted to
commence in the second half of 2014 with a 10 well (5.9 net)
drilling program. This program is targeted to add 5,900 BOE/d of
net production when complete.
- Canadian Natural previously acquired two blocks in Cote
d'Ivoire which are prospective for deepwater channel/fan structures
similar to Jubilee crude oil discoveries in Ghana and plays
elsewhere in offshore Africa.
-- Block CI-12 is located approximately 35 km west of the
Canadian Natural's current production at Espoir and Baobab and
Canadian Natural operates with a 60% working interest. The Company
shot a 3D seismic program in Q4/13 and the data is currently being
processed. Potential exploration drilling is targeted for 2015.
-- Canadian Natural has a 36% working interest in Block CI-514.
A seismic program has been completed and a drilling rig has been
contracted to commence drilling in March 2014, targeting to drill
the Lower Cretaceous formations, with structures targeted to
contain between 800 million barrels and 1,400 million barrels gross
oil originally in place (300 million barrels and 500 million
barrels net oil originally in place).
- In September 2012, the UK government announced the
implementation of the Brownfield Allowance ("BFA"), which allows
for a property development allowance on qualifying preapproved
field developments. This allowance partially mitigates the impact
of previous supplementary income tax increases. To date, Canadian
Natural has received approval for 3 BFAs. The Tiffany field BFA
resulted in a 2 well infill drilling program, which achieved first
oil in May 2013. The Ninian Field was awarded a BFA; the
development plan, which includes 4 new production wells, 4
injectors and 2 well upgrades, commenced in Q4/13.
- In Q4/11 the Banff/Kyle FPSO suffered damage from severe storm
conditions and was consequently removed from the field for repair.
The FPSO is currently undergoing repairs and is targeted to return
to the field during Q3/14. Subsequent to the tie-in of the FPSO,
the Banff/Kyle field is targeted to resume 3,500 bbl/d of net light
crude oil production.
- During 2013, the Company disposed of a 50% interest in its
exploration right in South Africa, for net cash consideration of
US$255 million, including a recovery of US$14 million of past
incurred costs, resulting in an after-tax gain on sale of
exploration and evaluation property of $166 million. In the event
that a commercial crude oil or natural gas discovery occurs on this
exploration right, resulting in the exploration right being
converted into a production right, an additional cash payment would
be due to the Company at such time, amounting to US$450 million for
a commercial crude oil discovery and US$120 million for a
commercial natural gas discovery. The operator is targeting to
commence drilling the first exploration well in Q3/14.
- The decommissioning activities at the Murchison platform
commenced in Q4/13 and the Company estimates the decommissioning
efforts will continue for approximately 5 years. In October 2013,
the Company entered into a Decommissioning Relief Deed ("DRD") with
the UK government. The DRD was introduced in 2013 and is a
contractual mechanism whereby the UK government guarantees its
participation in future field abandonments through a recovery of
PRT and corporate income tax.
North America Oil Sands Mining and Upgrading - Horizon
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Synthetic crude oil
production (bbl/d) 112,273 111,959 83,079 100,284 86,077
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Horizon achieved strong and reliable operating performance for
all of 2013. Horizon SCO production averaged approximately 112,000
bbl/d in the second half of 2013 upon the completion of the first
major turnaround. The Q4/13 production volumes of 112,273 bbl/d
represent a 35% increase from Q4/12 levels, indicating a step
change in safe, steady and reliable production at Horizon. Canadian
Natural expects continued strong operating performance in 2014, and
SCO production to date in 2014 has averaged approximately 111,000
bbl/d. Horizon production is targeted to increase by 11% in 2014
from 2013 levels as a result of the continued focus on effective
and efficient operations.
- Canadian Natural continues to deliver on its strategy to
transition to a longer life, low decline asset base which provides
significant and growing free cash flow. Canadian Natural's staged
expansion to 250,000 bbl/d of SCO production capacity continues to
progress on track and below sanctioned costs.
- An update to the staged Phase 2/3 physical completion of
expansion at the end of Q4/13 is as follows:
-- Overall Horizon Phase 2/3 expansion is 34% physically
complete.
-- Reliability - Tranche 2 is 94% physically complete. This
phase will increase performance, overall production reliability and
the Gas Recovery Unit will recover additional light oil barrels in
2014.
-- Directive 74 includes technological investment and research
into tailings management. This project remains on track and is
physically 24% complete.
-- Phase 2A is a coker expansion which will utilize pre-invested
infrastructure and equipment to expand the Coker Plant and
alleviate the current bottleneck. The expansion is 78% physically
complete with current progress tracking ahead of schedule. The
coker tie-in was originally scheduled to be completed in mid-2015;
however, due to strong construction performance and the early
completion of the coker installation, the Company has accelerated
the tie-in to September 2014. An increase in Horizon production
capacity of approximately 12,000 bbl/d is targeted to occur
subsequent to the completion of the coker tie-in.
-- Phase 2B is 24% physically complete. This phase expands the
capacity of major components such as gas/oil hydrotreatment, froth
treatment and the hydrogen plant. This phase is targeted to add
another 45,000 bbl/d of production capacity in 2016.
-- Phase 3 is on track and on schedule. This phase is 22%
physically complete, and includes the addition of supplementary
extraction trains. This phase is targeted to increase production
capacity by 80,000 bbl/d in 2017 and will result in additional
reliability, redundancy and significant operating cost savings.
-- The projects currently under construction continue to trend
at or below cost estimates.
- On the Phase 2/3 expansion Canadian Natural has committed
approximately 60% of the Engineering, Procurement and Construction
contracts. In addition, over 50% of the construction contracts have
been awarded to date, with 85% being lump sum, ensuring greater
cost certainty. To date, Canadian Natural is running approximately
10% below the original cost estimates.
MARKETING
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs pricing
WTI benchmark price
(US$/bbl) (1) $ 97.50 $ 105.82 $ 88.20 $ 98.00 $ 94.19
WCS blend differential
from WTI (%) (2) 33% 16% 21% 26% 22%
SCO price (US$/bbl) $ 88.37 $ 109.97 $ 91.90 $ 98.18 $ 92.59
Condensate benchmark
pricing (US$/bbl) $ 94.30 $ 103.83 $ 98.13 $ 101.67 $ 100.92
Average realized pricing
before risk management
(C$/bbl) (3) $ 69.38 $ 89.24 $ 66.55 $ 73.81 $ 72.44
Natural gas pricing
AECO benchmark price
(C$/GJ) $ 2.99 $ 2.68 $ 2.89 $ 3.00 $ 2.28
Average realized pricing
before risk management
(C$/Mcf) $ 3.62 $ 3.15 $ 3.42 $ 3.58 $ 2.70
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) West Texas Intermediate ("WTI").
(2) Western Canadian Select ("WCS").
(3) Average crude oil and NGLs pricing excludes SCO. Pricing is
net of blending costs and excluding risk management activities.
SCO Dated Brent Condensate
WTI WCS Blend Differential Differential Differential
Benchmark Pricing Differential from WTI from WTI from WTI
Pricing (US$/bbl) from WTI (%) (US$/bbl) (US$/bbl) (US$/bbl)
----------------------------------------------------------------------------
2013
October $100.55 26% $ (2.44) $ 8.49 $(1.92)
November $ 93.93 33% $(10.70) $ 14.03 $(6.41)
December $ 97.89 40% $(14.30) $ 12.92 $(1.38)
2014
January $ 94.86 31% $ (7.12) $ 13.40 $ 3.35
February $100.68 19% $ 1.97 $ 8.19 $ 5.15
March(i) $102.36 21% $ (0.95) $ 6.42 $ 3.37
----------------------------------------------------------------------------
(i)Based on current indicative pricing as at February 28,
2013.
- The WCS differential averaged 26% during 2013 compared with
22% in the previous year. During Q4/13 the WCS differential widened
to an average of 33% as a result of decreased heavy oil demand due
to planned refinery maintenance, pipeline logistical constraints
and third party unplanned refinery disruptions. The temporary
widening was in line with the Company's Q4/13 expectations. The
Company anticipates continued volatility in the WCS differential
for the first half of 2014 with a narrowing of the WCS differential
thereafter as additional heavy oil conversion and pipeline capacity
come on stream.
- WCS differentials to WTI widened to 40% in December. To
partially mitigate the cash flow impact from temporarily wider
differentials, the Company strategically curtailed production
levels by approximately 10,500 bbl/d of primary heavy crude oil
production volumes for approximately 30 days. Primary heavy crude
oil production volumes were deferred to January and February, when
differentials narrowed to 31% and 19% respectively.
- Subsequent to Q4/13, the WCS differential narrowed in January
2014 to average 31%, in February 2014 to average 19% and the
indicative differential for March 2014 is approximately 21%. The
WCS differential is directionally tightening due to increased
demand for heavier crudes, as a result of third party refinery
expansion and higher refinery utilization.
- Canadian Natural contributed 171,000 bbl/d of its heavy crude
oil stream to the WCS blend in 2013. The Company remains the
largest contributor of the WCS blend, accounting for 59%.
- During 2013, natural gas prices continued to recover from the
low pricing levels in 2012. Natural gas prices increased in Q4/13
from Q4/12 due to a return to normal natural gas storage levels.
Natural gas prices increased for Q4/13 from Q3/13 due to increased
winter weather related natural gas demand and changes in third
party short-term tolling arrangements.
NORTH WEST REDWATER UPGRADING AND REFINING
The North West Redwater refinery, upon completion, will
strengthen the Company's position by providing a competitive return
on investment and by adding 50,000 bbl/d of bitumen conversion
capacity in Alberta which will help reduce pricing volatility in
all Western Canadian heavy crude oil. The Company has a 50%
interest in the North West Redwater Partnership. Work is
progressing and site preparation and deep underground construction
is underway.
FINANCIAL REVIEW
The Company continues to implement proven strategies and its
disciplined approach to capital allocation. As a result, the
financial position of Canadian Natural remains strong. Canadian
Natural's cash flow generation, credit facilities, diverse asset
base and related capital expenditure programs and commodity hedging
policy all support a flexible financial position and provide the
appropriate financial resources for the near-, mid- and
long-term.
- The Company's strategy is to maintain a diverse portfolio
balanced across various commodity types. The Company achieved
production of 677,242 BOE/d for Q4/13 with approximately 97% of
production located in G8 countries.
- Canadian Natural has a strong balance sheet with debt to book
capitalization of 27% and debt to EBITDA of 1.1x at December 31,
2013.
- Canadian Natural maintains significant financial stability and
liquidity represented by approximately $2.9 billion of available
credit under its bank credit facilities, net of commercial paper
issued, as at December 31, 2013. In addition, the Company has
negotiated an additional $1 billion committed term facility with
the Bank of Montreal, which is available upon closing of the Devon
Asset acquisition.
- The Company's commodity hedging program protects investment
returns, ensures ongoing balance sheet strength and supports the
Company's cash flow for its capital expenditure programs. Details
of the Company's commodity hedging program can be found on the
Company's website at www.cnrl.com.
- For the year ended December 31, 2013, Canadian Natural has
purchased for cancellation under its Normal Course Issuer Bid
10,164,800 common shares at a weighted average price of $31.46 per
common share. Subsequent to December 31, 2013, to date in 2014 the
Company has purchased for cancellation 1,475,000 common shares at a
weighted average price of $35.85 per common share.
- Canadian Natural's Board of Directors has declared a quarterly
cash dividend on common shares of C$0.225 per share payable on
April 1, 2014. This increase is in addition to the aggregate
quarterly dividend increase of 90% announced during 2013 and is a
13% increase over the previous quarterly dividend. This is the
fourteenth consecutive year of dividend increases since the Company
first paid a dividend in 2001, with a compound annual growth rate
of 34% from 2009 when Horizon first commenced production.
OUTLOOK
For 2014, excluding production volumes associated with the Devon
Assets, annual production guidance is targeted to average between
521,000 and 560,000 bbl/d of crude oil and NGLs and between 1,170
and 1,210 MMcf/d of natural gas. Q1/14 production guidance before
royalties is forecast to average between 469,000 and 495,000 bbl/d
of crude oil and NGLs and between 1,166 and 1,186 MMcf/d of natural
gas. Detailed guidance on production levels, capital allocation and
operating costs can be found on the Company's website at
www.cnrl.com.
YEAR-END RESERVES
Determination of Reserves
For the year ended December 31, 2013 the Company retained
Independent Qualified Reserves Evaluators, Sproule Associates
Limited, Sproule International Limited and GLJ Petroleum
Consultants Ltd., 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 NGLs reserves
increased 2% to 4.42 billion barrels. Company Gross proved natural
gas reserves increased 4% to 4.31 Tcf. Total proved reserves
increased 2% to 5.14 billion BOE.
- Company Gross proved plus probable crude oil, SCO, bitumen and
NGLs reserves increased 1% to 6.97 billion barrels. Company Gross
proved plus probable natural gas reserves increased 6% to 6.11 Tcf.
Total proved plus probable reserves increased 1% to 7.99 billion
BOE.
- Company Gross proved reserve additions and revisions,
including acquisitions, were 266 million barrels of crude oil, SCO,
bitumen and NGLs and 592 billion cubic feet of natural gas for 364
million BOE. The total proved reserve replacement ratio was 149%.
The total proved reserve life index is 22.8 years.
- Company Gross proved plus probable reserve additions and
revisions, including acquisitions, were 227 million barrels of
crude oil, bitumen, SCO and NGLs and 745 billion cubic feet of
natural gas for 350 million BOE. The total proved plus probable
reserve replacement ratio was 143%. The total proved plus probable
reserve life index is 35.4 years.
- Proved undeveloped crude oil, SCO, bitumen and NGLs reserves
accounted for 30% 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
- Company Gross proved crude oil, bitumen and NGLs reserves
increased 8% to 1.89 billion barrels. Company Gross proved natural
gas reserves increased 4% to 4.16 Tcf. Total proved BOE increased
7% to 2.58 billion barrels.
- Company Gross proved plus probable crude oil, bitumen and NGLs
reserves increased 4% to 3.21 billion barrels. Company Gross proved
plus probable natural gas reserves increased 6% to 5.88 Tcf. Total
proved plus probable BOE increased 4% to 4.19 billion barrels.
- Company Gross proved reserve additions and revisions,
including acquisitions, were 268 million barrels of crude oil,
bitumen and NGLs and 587 billion cubic feet of natural gas for 366
million BOE. The total proved reserve replacement ratio is 188%.
The total proved reserve life index in 14.8 years.
- Company Gross proved plus probable reserve additions and
revisions, including acquisitions, were 252 million barrels of
crude oil, bitumen and NGLs and 719 billion cubic feet of natural
gas for 372 million BOE. The total proved plus probable reserve
replacement ratio was 191%. The total proved plus probable reserve
life index is 23.9 years.
- Proved undeveloped crude oil, bitumen and NGLs reserves
accounted for 37% of the North America total proved reserves and
proved undeveloped natural gas reserves accounted for 7% of the
North America total proved reserves.
- Thermal oil sands (bitumen) Company Gross proved reserves
increased 9% to 1.16 billion 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 reserve additions and revisions were 126 million
barrels. Total proved plus probable bitumen reserves increased 2%
to 2.17 billion barrels.
North America Oil Sands Mining and Upgrading
- Company Gross proved plus probable SCO reserves decreased 2%
to 3.29 billion barrels, primarily due to 2013 production, as well
as the consumption of distillate, commencing in 2014, to produce
on-site diesel fuel and reduce operating costs.
International Exploration and Production
- North Sea Company Gross proved reserves are unchanged at 239
million BOE. North Sea Company Gross proved plus probable reserves
are 346 million BOE.
- Offshore Africa Company Gross proved reserves decreased 6% to
108 million BOE primarily due to production. Offshore Africa
Company Gross proved plus probable reserves are 170 million
BOE.
Summary of Company Gross Crude Oil, Bitumen, Natural Gas & NGL Reserves
As of December 31, 2013
Forecast Prices and Costs
Light and Primary Pelican Lake Bitumen
Medium Oil Heavy Heavy Oil (Thermal Oil)
MMbbl Oil MMbbl MMbbl MMbbl
----------------------------------------------------------------------------
North America
Proved
Developed
Producing 95 123 216 321
Developed Non-
Producing 4 23 1 90
Undeveloped 18 98 41 746
----------------------------------------------------------------------------
Total Proved 117 244 258 1,157
Probable 49 90 104 1,013
----------------------------------------------------------------------------
Total Proved
plus Probable 166 334 362 2,170
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
Proved
Developed
Producing 38
Developed Non-
Producing 18
Undeveloped 168
----------------------------------------------------------------------------
Total Proved 224
Probable 101
----------------------------------------------------------------------------
Total Proved
plus Probable 325
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
Proved
Developed
Producing 34
Developed Non-
Producing -
Undeveloped 65
----------------------------------------------------------------------------
Total Proved 99
Probable 54
----------------------------------------------------------------------------
Total Proved
plus Probable 153
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
Proved
Developed
Producing 167 123 216 321
Developed Non-
Producing 22 23 1 90
Undeveloped 251 98 41 746
----------------------------------------------------------------------------
Total Proved 440 244 258 1,157
Probable 204 90 104 1,013
----------------------------------------------------------------------------
Total Proved
plus Probable 644 334 362 2,170
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Synthetic Barrels of Oil
Crude Natural Natural Gas Equivalent
Oil MMbbl Gas Bcf Liquids MMbbl MMBOE
----------------------------------------------------------------------------
North America
Proved
Developed
Producing 1,848 2,773 63 3,128
Developed Non-
Producing - 251 4 164
Undeveloped 363 1,136 43 1,498
----------------------------------------------------------------------------
Total Proved 2,211 4,160 110 4,790
Probable 1,078 1,721 64 2,685
----------------------------------------------------------------------------
Total Proved
plus Probable 3,289 5,881 174 7,475
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
Proved
Developed
Producing 8 39
Developed Non-
Producing 63 28
Undeveloped 20 172
----------------------------------------------------------------------------
Total Proved 91 239
Probable 34 107
----------------------------------------------------------------------------
Total Proved
plus Probable 125 346
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
Proved
Developed
Producing 40 41
Developed Non-
Producing - -
Undeveloped 14 67
----------------------------------------------------------------------------
Total Proved 54 108
Probable 49 62
----------------------------------------------------------------------------
Total Proved
plus Probable 103 170
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
Proved
Developed
Producing 1,848 2,821 63 3,208
Developed Non-
Producing - 314 4 192
Undeveloped 363 1,170 43 1,737
----------------------------------------------------------------------------
Total Proved 2,211 4,305 110 5,137
Probable 1,078 1,804 64 2,854
----------------------------------------------------------------------------
Total Proved
plus Probable 3,289 6,109 174 7,991
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Summary of Company Net Crude Oil, Bitumen, Natural Gas & NGL Reserves
As of December 31, 2013
Forecast Prices and Costs
Light and Pelican Bitumen
Medium Oil Primary Heavy Lake Heavy (Thermal Oil)
MMbbl Oil MMbbl Oil MMbbl MMbbl
----------------------------------------------------------------------------
North America
Proved
Developed
Producing 82 101 164 244
Developed Non-
Producing 3 19 1 65
Undeveloped 15 82 32 574
----------------------------------------------------------------------------
Total Proved 100 202 197 883
Probable 40 72 71 776
----------------------------------------------------------------------------
Total Proved
plus Probable 140 274 268 1,659
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
Proved
Developed
Producing 38
Developed Non-
Producing 18
Undeveloped 168
----------------------------------------------------------------------------
Total Proved 224
Probable 101
----------------------------------------------------------------------------
Total Proved
plus Probable 325
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
Proved
Developed
Producing 29
Developed Non-
Producing -
Undeveloped 51
----------------------------------------------------------------------------
Total Proved 80
Probable 42
----------------------------------------------------------------------------
Total Proved
plus Probable 122
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
Proved
Developed
Producing 149 101 164 244
Developed Non-
Producing 21 19 1 65
Undeveloped 234 82 32 574
----------------------------------------------------------------------------
Total Proved 404 202 197 883
Probable 183 72 71 776
----------------------------------------------------------------------------
Total Proved
plus Probable 587 274 268 1,659
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Synthetic Barrels of Oil
Crude Natural Natural Gas Equivalent
Oil MMbbl Gas Bcf Liquids MMbbl MMBOE
----------------------------------------------------------------------------
North America
Proved
Developed
Producing 1,564 2,485 45 2,614
Developed Non-
Producing - 211 2 125
Undeveloped 263 988 34 1,165
----------------------------------------------------------------------------
Total Proved 1,827 3,684 81 3,904
Probable 836 1,454 50 2,087
----------------------------------------------------------------------------
Total Proved
plus Probable 2,663 5,138 131 5,991
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
Proved
Developed
Producing 8 39
Developed Non-
Producing 63 28
Undeveloped 20 172
----------------------------------------------------------------------------
Total Proved 91 239
Probable 34 107
----------------------------------------------------------------------------
Total Proved
plus Probable 125 346
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
Proved
Developed
Producing 27 34
Developed Non-
Producing - -
Undeveloped 11 53
----------------------------------------------------------------------------
Total Proved 38 87
Probable 32 47
----------------------------------------------------------------------------
Total Proved
plus Probable 70 134
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
Proved
Developed
Producing 1,564 2,520 45 2,687
Developed Non-
Producing - 274 2 153
Undeveloped 263 1,019 34 1,390
----------------------------------------------------------------------------
Total Proved 1,827 3,813 81 4,230
Probable 836 1,520 50 2,241
----------------------------------------------------------------------------
Total Proved
plus Probable 2,663 5,333 131 6,471
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliation of Company Gross Reserves by Product
As of December 31, 2013
Forecast Prices and Costs
PROVED
Light and Primary Pelican Lake Bitumen
Medium Heavy Heavy (Thermal Oil)
North America Oil MMbbl Oil MMbbl Oil MMbbl MMbbl
----------------------------------------------------------------------------
December 31,
2012 113 204 267 1,066
----------------------------------------------------------------------------
Discoveries - 1 - -
Extensions 3 36 - 51
Infill Drilling 5 11 2 -
Improved
Recovery - 1 - -
Acquisitions 9 - - -
Dispositions - - - -
Economic Factors 1 1 - 2
Technical
Revisions 2 40 5 73
Production (16) (50) (16) (35)
----------------------------------------------------------------------------
December 31,
2013 117 244 258 1,157
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
----------------------------------------------------------------------------
December 31,
2012 227
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling -
Improved
Recovery -
Acquisitions 6
Dispositions -
Economic Factors -
Technical
Revisions (2)
Production (7)
----------------------------------------------------------------------------
December 31,
2013 224
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
----------------------------------------------------------------------------
December 31,
2012 103
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling -
Improved
Recovery -
Acquisitions -
Dispositions -
Economic Factors -
Technical
Revisions 1
Production (5)
----------------------------------------------------------------------------
December 31,
2013 99
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
----------------------------------------------------------------------------
December 31,
2012 443 204 267 1,066
----------------------------------------------------------------------------
Discoveries - 1 - -
Extensions 3 36 - 51
Infill Drilling 5 11 2 -
Improved
Recovery - 1 - -
Acquisitions 15 - - -
Dispositions - - - -
Economic Factors 1 1 - 2
Technical
Revisions 1 40 5 73
Production (28) (50) (16) (35)
----------------------------------------------------------------------------
December 31,
2013 440 244 258 1,157
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Synthetic Barrels of Oil
Crude Oil Natural Natural Gas Equivalent
North America MMbbl Gas Bcf Liquids MMbbl MMBOE
----------------------------------------------------------------------------
December 31,
2012 2,255 3,985 94 4,663
----------------------------------------------------------------------------
Discoveries - 6 - 2
Extensions - 163 13 130
Infill Drilling - 73 3 33
Improved
Recovery - 1 - 1
Acquisitions - 141 2 35
Dispositions - (1) - -
Economic Factors (2) (99) (1) (16)
Technical
Revisions (5) 303 8 173
Production (37) (412) (9) (231)
----------------------------------------------------------------------------
December 31,
2013 2,211 4,160 110 4,790
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
----------------------------------------------------------------------------
December 31,
2012 82 240
----------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - -
Improved
Recovery - -
Acquisitions 15 8
Dispositions - -
Economic Factors - -
Technical
Revisions (4) (2)
Production (2) (7)
----------------------------------------------------------------------------
December 31,
2013 91 239
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
----------------------------------------------------------------------------
December 31,
2012 69 115
----------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - -
Improved
Recovery - -
Acquisitions - -
Dispositions - -
Economic Factors - -
Technical
Revisions (6) -
Production (9) (7)
----------------------------------------------------------------------------
December 31,
2013 54 108
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
----------------------------------------------------------------------------
December 31,
2012 2,255 4,136 94 5,018
----------------------------------------------------------------------------
Discoveries - 6 - 2
Extensions - 163 13 130
Infill Drilling - 73 3 33
Improved
Recovery - 1 - 1
Acquisitions - 156 2 43
Dispositions - (1) - -
Economic Factors (2) (99) (1) (16)
Technical
Revisions (5) 293 8 171
Production (37) (423) (9) (245)
----------------------------------------------------------------------------
December 31,
2013 2,211 4,305 110 5,137
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliation of Company Gross Reserves by Product
As of December 31, 2013
Forecast Prices and Costs
PROBABLE
Light and Primary Pelican Lake Bitumen
Medium Heavy Heavy (Thermal Oil)
North America Oil MMbbl Oil MMbbl Oil MMbbl MMbbl
----------------------------------------------------------------------------
December 31,
2012 51 80 105 1,056
----------------------------------------------------------------------------
Discoveries - - - -
Extensions 2 19 - 49
Infill Drilling 1 4 - -
Improved
Recovery - - - -
Acquisitions 3 - - -
Dispositions - - - -
Economic Factors 1 - 1 (2)
Technical
Revisions (9) (13) (2) (90)
Production - - - -
----------------------------------------------------------------------------
December 31,
2013 49 90 104 1,013
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
----------------------------------------------------------------------------
December 31,
2012 105
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling -
Improved
Recovery -
Acquisitions 1
Dispositions -
Economic Factors -
Technical
Revisions (5)
Production -
----------------------------------------------------------------------------
December 31,
2013 101
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
----------------------------------------------------------------------------
December 31,
2012 55
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling -
Improved
Recovery -
Acquisitions -
Dispositions -
Economic Factors (1)
Technical
Revisions -
Production -
----------------------------------------------------------------------------
December 31,
2013 54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
----------------------------------------------------------------------------
December 31,
2012 211 80 105 1,056
----------------------------------------------------------------------------
Discoveries - - - -
Extensions 2 19 - 49
Infill Drilling 1 4 - -
Improved
Recovery - - - -
Acquisitions 4 - - -
Dispositions - - - -
Economic Factors - - 1 (2)
Technical
Revisions (14) (13) (2) (90)
Production - - - -
----------------------------------------------------------------------------
December 31,
2013 204 90 104 1,013
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Synthetic Barrels of Oil
Crude Natural Natural Gas Equivalent
North America Oil MMbbl Gas Bcf Liquids MMbbl MMBOE
----------------------------------------------------------------------------
December 31,
2012 1,096 1,589 44 2,697
----------------------------------------------------------------------------
Discoveries - 1 1 1
Extensions - 261 20 134
Infill Drilling - 19 - 8
Improved
Recovery - - - -
Acquisitions - 35 - 8
Dispositions - - - -
Economic Factors 1 18 - 4
Technical
Revisions (19) (202) (1) (167)
Production - - - -
----------------------------------------------------------------------------
December 31,
2013 1,078 1,721 64 2,685
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
----------------------------------------------------------------------------
December 31,
2012 20 109
----------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - -
Improved
Recovery - -
Acquisitions 5 2
Dispositions - -
Economic Factors - -
Technical
Revisions 9 (4)
Production - -
----------------------------------------------------------------------------
December 31,
2013 34 107
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
----------------------------------------------------------------------------
December 31,
2012 42 62
----------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - -
Improved
Recovery - -
Acquisitions - -
Dispositions - -
Economic Factors - (1)
Technical
Revisions 7 1
Production - -
----------------------------------------------------------------------------
December 31,
2013 49 62
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
----------------------------------------------------------------------------
December 31,
2012 1,096 1,651 44 2,868
----------------------------------------------------------------------------
Discoveries - 1 1 1
Extensions - 261 20 134
Infill Drilling - 19 - 8
Improved
Recovery - - - -
Acquisitions - 40 - 10
Dispositions - - - -
Economic Factors 1 18 - 3
Technical
Revisions (19) (186) (1) (170)
Production - - - -
----------------------------------------------------------------------------
December 31,
2013 1,078 1,804 64 2,854
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reconciliation of Company Gross Reserves by Product
As of December 31, 2013
Forecast Prices and Costs
PROVED PLUS PROBABLE
Light and Primary Pelican Lake Bitumen
Medium Heavy Heavy (Thermal Oil)
North America Oil MMbbl Oil MMbbl Oil MMbbl MMbbl
----------------------------------------------------------------------------
December 31,
2012 164 284 372 2,122
----------------------------------------------------------------------------
Discoveries - 1 - -
Extensions 5 55 - 100
Infill Drilling 6 15 2 -
Improved
Recovery - 1 - -
Acquisitions 12 - - -
Dispositions - - - -
Economic Factors 2 1 1 -
Technical
Revisions (7) 27 3 (17)
Production (16) (50) (16) (35)
----------------------------------------------------------------------------
December 31,
2013 166 334 362 2,170
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
----------------------------------------------------------------------------
December 31,
2012 332
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling -
Improved
Recovery -
Acquisitions 7
Dispositions -
Economic Factors -
Technical
Revisions (7)
Production (7)
----------------------------------------------------------------------------
December 31,
2013 325
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
----------------------------------------------------------------------------
December 31,
2012 158
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling -
Improved
Recovery -
Acquisitions -
Dispositions -
Economic Factors (1)
Technical
Revisions 1
Production (5)
----------------------------------------------------------------------------
December 31,
2013 153
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
----------------------------------------------------------------------------
December 31,
2012 654 284 372 2,122
----------------------------------------------------------------------------
Discoveries - 1 - -
Extensions 5 55 - 100
Infill Drilling 6 15 2 -
Improved
Recovery - 1 - -
Acquisitions 19 - - -
Dispositions - - - -
Economic Factors 1 1 1 -
Technical
Revisions (13) 27 3 (17)
Production (28) (50) (16) (35)
----------------------------------------------------------------------------
December 31,
2013 644 334 362 2,170
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Synthetic Barrels of Oil
Crude Natural Natural Gas Equivalent
North America Oil MMbbl Gas Bcf Liquids MMbbl MMBOE
----------------------------------------------------------------------------
December 31,
2012 3,351 5,574 138 7,360
----------------------------------------------------------------------------
Discoveries - 7 1 3
Extensions - 424 33 264
Infill Drilling - 92 3 41
Improved
Recovery - 1 - 1
Acquisitions - 176 2 43
Dispositions - (1) - -
Economic Factors (1) (81) (1) (12)
Technical
Revisions (24) 101 7 6
Production (37) (412) (9) (231)
----------------------------------------------------------------------------
December 31,
2013 3,289 5,881 174 7,475
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
----------------------------------------------------------------------------
December 31,
2012 102 349
----------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - -
Improved
Recovery - -
Acquisitions 20 10
Dispositions - -
Economic Factors - -
Technical
Revisions 5 (6)
Production (2) (7)
----------------------------------------------------------------------------
December 31,
2013 125 346
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
----------------------------------------------------------------------------
December 31,
2012 111 177
----------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - -
Improved
Recovery - -
Acquisitions - -
Dispositions - -
Economic Factors - (1)
Technical
Revisions 1 1
Production (9) (7)
----------------------------------------------------------------------------
December 31,
2013 103 170
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
----------------------------------------------------------------------------
December 31,
2012 3,351 5,787 138 7,886
----------------------------------------------------------------------------
Discoveries - 7 1 3
Extensions - 424 33 264
Infill Drilling - 92 3 41
Improved
Recovery - 1 - 1
Acquisitions - 196 2 53
Dispositions - (1) - -
Economic Factors (1) (81) (1) (13)
Technical
Revisions (24) 107 7 1
Production (37) (423) (9) (245)
----------------------------------------------------------------------------
December 31,
2013 3,289 6,109 174 7,991
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Reserves Notes:
(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) BOE values may not calculate due to rounding.
(4) Forecast pricing assumptions utilized by the Independent
Qualified Reserves Evaluators in the reserve estimates were
provided by Sproule
Associates Limited:
Average
annual
increase
2014 2015 2016 2017 2018 thereafter
----------------------------------------------------------------------------
Crude oil and NGLs
WTI at Cushing
(US$/bbl) 94.65 88.37 84.25 95.52 96.96 1.50%
Western Canada Select
(C$/bbl) 77.81 75.02 75.29 85.36 86.64 1.50%
Edmonton Par (C$/bbl) 92.64 89.31 89.63 101.62 103.14 1.50%
Edmonton Pentanes+
(C$/bbl) 103.50 99.78 100.14 113.53 115.24 1.50%
North Sea Brent
(US$/bbl) 108.06 102.73 97.42 106.14 107.73 1.50%
----------------------------------------------------------------------------
Natural gas
AECO (C$/MMBtu) 4.00 3.99 4.00 4.93 5.01 1.50%
BC Westcoast Station 2
(C$/MMBtu) 3.95 3.94 3.95 4.88 4.96 1.50%
Henry Hub Louisiana
(US$/MMBtu) 4.17 4.15 4.17 5.04 5.12 1.50%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
A foreign exchange rate of 0.9400 US$/Cdn$ was used in the 2013
evaluation.
(5) Reserve additions and revisions are comprised of all
categories of Company Gross reserve changes, exclusive of
production.
(6) Reserve replacement ratio is the Company Gross reserve
additions and revisions divided by the Company Gross production in
the same period.
(7) 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.
(8) Reserve Life Index is based on the amount for the relevant
reserve category divided by the 2014 proved developed producing
production forecast prepared by the Independent Qualified Reserve
Evaluators.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources
Limited (the "Company") in this document or documents incorporated
herein by reference constitute forward-looking statements or
information (collectively referred to herein as "forward-looking
statements") within the meaning of applicable securities
legislation. Forward-looking statements can be identified by the
words "believe", "anticipate", "expect", "plan", "estimate",
"target", "continue", "could", "intend", "may", "potential",
"predict", "should", "will", "objective", "project", "forecast",
"goal", "guidance", "outlook", "effort", "seeks", "schedule",
"proposed" or expressions of a similar nature suggesting future
outcome or statements regarding an outlook. Disclosure related to
expected future commodity pricing, forecast or anticipated
production volumes, royalties, operating costs, capital
expenditures, income tax expenses and other guidance provided
throughout this Management's Discussion and Analysis ("MD&A"),
constitute forward-looking statements. Disclosure of plans relating
to and expected results of existing and future developments,
including but not limited to the Horizon Oil Sands operations and
future expansions, Primrose thermal projects, Pelican Lake water
and polymer flood project, the Kirby Thermal Oil Sands Project,
construction of the proposed Keystone XL Pipeline from Hardisty,
Alberta to the US Gulf Coast, construction of the proposed Energy
East pipeline to transport crude oil from Alberta to Quebec and New
Brunswick, the proposed Kinder Morgan Trans Mountain pipeline
expansion from Edmonton, Alberta to Vancouver, British Columbia,
and the construction and future operations of the North West
Redwater bitumen upgrader and refinery also constitute
forward-looking statements. This forward-looking information is
based on annual budgets and multi-year forecasts, and is reviewed
and revised throughout the year as necessary in the context of
targeted financial ratios, project returns, product pricing
expectations and balance in project risk and time horizons. These
statements are not guarantees of future performance and are subject
to certain risks. The reader should not place undue reliance on
these forward-looking statements as there can be no assurances that
the plans, initiatives or expectations upon which they are based
will occur.
In addition, statements relating to "reserves" are deemed to be
forward-looking statements as they involve the implied assessment
based on certain estimates and assumptions that the reserves
described can be profitably produced in the future. There are
numerous uncertainties inherent in estimating quantities of proved
and proved plus probable crude oil, natural gas and natural gas
liquids ("NGLs") reserves and in projecting future rates of
production and the timing of development expenditures. The total
amount or timing of actual future production may vary significantly
from reserve and production estimates.
The forward-looking statements are based on current
expectations, estimates and projections about the Company and the
industry in which the Company operates, which speak only as of the
date such statements were made or as of the date of the report or
document in which they are contained, and are subject to known and
unknown risks and uncertainties that could cause the actual
results, performance or achievements of the Company to be
materially different from any future results, performance or
achievements expressed or implied by such forward-looking
statements. Such risks and uncertainties include, among others:
general economic and business conditions which will, among other
things, impact demand for and market prices of the Company's
products; volatility of and assumptions regarding crude oil and
natural gas prices; fluctuations in currency and interest rates;
assumptions on which the Company's current guidance is based;
economic conditions in the countries and regions in which the
Company conducts business; political uncertainty, including actions
of or against terrorists, insurgent groups or other conflict
including conflict between states; industry capacity; ability of
the Company to implement its business strategy, including
exploration and development activities; impact of competition; the
Company's defense of lawsuits; availability and cost of seismic,
drilling and other equipment; ability of the Company and its
subsidiaries to complete capital programs; the Company's and its
subsidiaries' ability to secure adequate transportation for its
products; unexpected disruptions or delays in the resumption of the
mining, extracting or upgrading of the Company's bitumen products;
potential delays or changes in plans with respect to exploration or
development projects or capital expenditures; ability of the
Company to attract the necessary labour required to build its
thermal and oil sands mining projects; operating hazards and other
difficulties inherent in the exploration for and production and
sale of crude oil and natural gas and in mining, extracting or
upgrading the Company's bitumen products; availability and cost of
financing; the Company's and its subsidiaries' success of
exploration and development activities and their ability to replace
and expand crude oil and natural gas reserves; timing and success
of integrating the business and operations of acquired companies;
production levels; imprecision of reserve estimates and estimates
of recoverable quantities of crude oil, natural gas and NGLs not
currently classified as proved; actions by governmental
authorities; government regulations and the expenditures required
to comply with them (especially safety and environmental laws and
regulations and the impact of climate change initiatives on capital
and operating costs); asset retirement obligations; the adequacy of
the Company's provision for taxes; and other circumstances
affecting revenues and expenses.
The Company's operations have been, and in the future may be,
affected by political developments and by federal, provincial and
local laws and regulations such as restrictions on production,
changes in taxes, royalties and other amounts payable to
governments or governmental agencies, price or gathering rate
controls and environmental protection regulations. Should one or
more of these risks or uncertainties materialize, or should any of
the Company's assumptions prove incorrect, actual results may vary
in material respects from those projected in the forward-looking
statements. The impact of any one factor on a particular
forward-looking statement is not determinable with certainty as
such factors are dependent upon other factors, and the Company's
course of action would depend upon its assessment of the future
considering all information then available.
Readers are cautioned that the foregoing list of factors is not
exhaustive. Unpredictable or unknown factors not discussed in this
report could also have material adverse effects on forward-looking
statements. Although the Company believes that the expectations
conveyed by the forward-looking statements are reasonable based on
information available to it on the date such forward-looking
statements are made, no assurances can be given as to future
results, levels of activity and achievements. All subsequent
forward-looking statements, whether written or oral, attributable
to the Company or persons acting on its behalf are expressly
qualified in their entirety by these cautionary statements. Except
as required by law, the Company assumes no obligation to update
forward-looking statements, whether as a result of new information,
future events or other factors, or the foregoing factors affecting
this information, should circumstances or Management's estimates or
opinions change.
Management's Discussion and Analysis
This MD&A of the financial condition and results of
operations of the Company should be read in conjunction with the
unaudited interim consolidated financial statements for the three
months and year ended December 31, 2013 and the MD&A and the
audited consolidated financial statements for the year ended
December 31, 2012.
All dollar amounts are referenced in millions of Canadian
dollars, except where noted otherwise. The Company's unaudited
interim consolidated financial statements for the period ended
December 31, 2013 and this MD&A have been prepared in
accordance with International Financial Reporting Standards
("IFRS") as issued by the International Accounting Standards Board.
This MD&A includes references to financial measures commonly
used in the crude oil and natural gas industry, such as adjusted
net earnings from operations, cash flow from operations, and cash
production costs. These financial measures are not defined by IFRS
and therefore are referred to as non-GAAP measures. The non-GAAP
measures used by the Company may not be comparable to similar
measures presented by other companies. The Company uses these
non-GAAP measures to evaluate its performance. The non-GAAP
measures should not be considered an alternative to or more
meaningful than net earnings, as determined in accordance with
IFRS, as an indication of the Company's performance. The non-GAAP
measures adjusted net earnings from operations and cash flow from
operations are reconciled to net earnings, as determined in
accordance with IFRS, in the "Financial Highlights" section of this
MD&A. The derivation of adjusted cash production costs and
adjusted depreciation, depletion and amortization are included in
the "Operating Highlights - Oil Sands Mining and Upgrading" section
of this MD&A. The Company also presents certain non-GAAP
financial ratios and their derivation in the "Liquidity and Capital
Resources" section of this MD&A.
A Barrel of Oil Equivalent ("BOE") is derived by converting six
thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of
crude oil (6 Mcf:1 bbl). This conversion may be misleading,
particularly if used in isolation, since the 6 Mcf:1 bbl ratio is
based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value
equivalency at the wellhead. In comparing the value ratio using
current crude oil prices relative to natural gas prices, the 6
Mcf:1 bbl conversion ratio may be misleading as an indication of
value. In addition, for the purposes of this MD&A, crude oil is
defined to include the following commodities: light and medium
crude oil, primary heavy crude oil, Pelican Lake heavy crude oil,
bitumen (thermal oil), and synthetic crude oil.
Production volumes and per unit statistics are presented
throughout this MD&A on a "before royalty" or "gross" basis,
and realized prices are net of blending costs and exclude the
effect of risk management activities. Production on an "after
royalty" or "net" basis is also presented for information purposes
only.
The Company's 2014 guidance included in this MD&A does not
reflect the potential impact of the agreement announced on February
19, 2014 to acquire certain producing Canadian crude oil and
natural gas properties based on a targeted closing date of April 1,
2014.
The following discussion refers primarily to the Company's
financial results for the three months and year ended December 31,
2013 in relation to the comparable periods in 2012 and the third
quarter of 2013. The accompanying tables form an integral part of
this MD&A. Additional information relating to the Company,
including its Annual Information Form for the year ended December
31, 2012, is available on SEDAR at www.sedar.com, and on EDGAR at
www.sec.gov. This MD&A is dated March 5, 2014.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Product sales $ 4,330 $ 5,284 $ 4,059 $ 17,945 $ 16,195
Net earnings $ 413 $ 1,168 $ 352 $ 2,270 $ 1,892
Per common share - basic $ 0.38 $ 1.07 $ 0.32 $ 2.08 $ 1.72
- diluted $ 0.38 $ 1.07 $ 0.32 $ 2.08 $ 1.72
Adjusted net earnings from
operations (1) $ 563 $ 1,009 $ 359 $ 2,435 $ 1,618
Per common share - basic $ 0.52 $ 0.93 $ 0.33 $ 2.24 $ 1.48
- diluted $ 0.52 $ 0.93 $ 0.33 $ 2.23 $ 1.47
Cash flow from operations
(2) $ 1,782 $ 2,454 $ 1,548 $ 7,477 $ 6,013
Per common share - basic $ 1.64 $ 2.26 $ 1.41 $ 6.87 $ 5.48
- diluted $ 1.64 $ 2.26 $ 1.41 $ 6.86 $ 5.47
Capital expenditures, net
of dispositions $ 2,091 $ 1,655 $ 1,767 $ 7,274 $ 6,308
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Adjusted net earnings from operations is a non-GAAP measure
that represents net earnings adjusted for certain items of a
non-operational nature. The Company evaluates its performance based
on adjusted net earnings from operations. The reconciliation
"Adjusted Net Earnings from Operations" presents the after-tax
effects of certain items of a non-operational nature that are
included in the Company's financial results. Adjusted net earnings
from operations may not be comparable to similar measures presented
by other companies.
(2) Cash flow from operations is a non-GAAP measure that
represents net earnings adjusted for non-cash items before working
capital adjustments. The Company evaluates its performance based on
cash flow from operations. The Company considers cash flow from
operations a key measure as it demonstrates the Company's ability
to generate the cash flow necessary to fund future growth through
capital investment and to repay debt. The reconciliation "Cash Flow
from Operations" presents certain non-cash items that are included
in the Company's financial results. Cash flow from operations may
not be comparable to similar measures presented by other
companies.
Adjusted Net Earnings from Operations
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Net earnings as reported $ 413 $ 1,168 $ 352 $ 2,270 $ 1,892
Share-based compensation,
net of tax (1) 65 48 (41) 135 (214)
Unrealized risk management
(gain) loss, net of tax
(2) (26) 99 4 32 (37)
Unrealized foreign
exchange loss (gain), net
of tax (3) 111 (75) 254 226 129
Realized foreign exchange
gain on repayment of US
dollar debt securities,
net of tax (4) - - (210) (12) (210)
Gain on corporate
acquisition/disposition
of properties, net of tax
(5) - (231) - (231) -
Effect of statutory tax
rate and other
legislative changes on
deferred income tax
liabilities (6) - - - 15 58
----------------------------------------------------------------------------
Adjusted net earnings from
operations $ 563 $ 1,009 $ 359 $ 2,435 $ 1,618
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company's employee stock option plan provides for a cash
payment option. Accordingly, the fair value of the outstanding
vested options is recorded as a liability on the Company's balance
sheets and periodic changes in the fair value are recognized in net
earnings or are capitalized to Oil Sands Mining and Upgrading
construction costs.
(2) Derivative financial instruments are recorded at fair value
on the Company's balance sheets, with changes in the fair value of
non-designated hedges recognized in net earnings. The amounts
ultimately realized may be materially different than reflected in
the financial statements due to changes in prices of the underlying
items hedged, primarily crude oil and natural gas.
(3) Unrealized foreign exchange gains and losses result
primarily from the translation of US dollar denominated long-term
debt to period-end exchange rates, partially offset by the impact
of cross currency swaps, and are recognized in net earnings.
(4) During the first quarter of 2013, the Company repaid US$400
million of 5.15% notes. During the fourth quarter of 2012, the
Company repaid US$350 million of 5.45% notes.
(5) During the third quarter of 2013, the Company recorded an
after-tax gain of $231 million related to the acquisition of
Barrick Energy Inc. and the disposition of a 50% working interest
in an exploration right in South Africa.
(6) All substantively enacted adjustments in applicable income
tax rates and other legislative changes are applied to underlying
assets and liabilities on the Company's balance sheets in
determining deferred income tax assets and liabilities. The impact
of these tax rate and other legislative changes is recorded in net
earnings during the period the legislation is substantively
enacted. During the second quarter of 2013, the Government of
British Columbia substantively enacted legislation to increase its
provincial corporate income tax rate effective April 1, 2013,
resulting in an increase in the Company's deferred income tax
liability of $15 million. 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 $58 million.
Cash Flow from Operations
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Net earnings $ 413 $ 1,168 $ 352 $ 2,270 $ 1,892
Non-cash items:
Depletion, depreciation
and amortization 1,272 1,258 1,213 4,844 4,328
Share-based compensation 65 48 (41) 135 (214)
Asset retirement
obligation accretion 46 41 38 171 151
Unrealized risk
management (gain) loss (30) 121 8 39 (42)
Unrealized foreign
exchange loss (gain) 111 (75) 254 226 129
Realized foreign
exchange gain on
repayment of US dollar
debt securities - - (210) (12) (210)
Equity loss from joint
venture 1 1 3 4 9
Deferred income tax
(recovery) expense (96) 123 (69) 31 (30)
Gain on corporate
acquisition/disposition
of properties - (289) - (289) -
Current income tax on
disposition of properties - 58 - 58 -
----------------------------------------------------------------------------
Cash flow from operations $ 1,782 $ 2,454 $ 1,548 $ 7,477 $ 6,013
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
Net earnings for the year ended December 31, 2013 were $2,270
million compared with $1,892 million for the year ended December
31, 2012. Net earnings for the year ended December 31, 2013
included net after-tax expenses of $165 million compared with net
after-tax income of $274 million for the year ended December 31,
2012 related to the effects of share-based compensation, risk
management activities, fluctuations in foreign exchange rates
including the impact of a realized foreign exchange gain on
repayment of long-term debt, the gain on corporate
acquisition/disposition of properties, 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, 2013 were $2,435 million
compared with $1,618 million for the year ended December 31,
2012.
Net earnings for the fourth quarter of 2013 were $413 million
compared with $352 million for the fourth quarter of 2012 and
$1,168 million for the third quarter of 2013. Net earnings for the
fourth quarter of 2013 included net after-tax expenses of $150
million compared with net after-tax expense of $7 million for the
fourth quarter of 2012 and net after-tax income of $159 million for
the third quarter of 2013 related to the effects of share-based
compensation, risk management activities, fluctuations in foreign
exchange rates including the impact of a realized foreign exchange
gain on repayment of long-term debt, and the gain on corporate
acquisition/disposition of properties. Excluding these items,
adjusted net earnings from operations for the fourth quarter of
2013 were $563 million compared with $359 million for the fourth
quarter of 2012 and $1,009 million for the third quarter of
2013.
The increase in adjusted net earnings for the year ended
December 31, 2013 from the comparable period in 2012 was primarily
due to:
- higher crude oil and NGLs and synthetic crude oil ("SCO")
sales volumes in the North America and Oil Sands Mining and
Upgrading segments;
- higher realized SCO prices;
- higher natural gas netbacks;
- higher realized risk management gains; and
- the impact of a weaker Canadian dollar relative to the US
dollar;
partially offset by:
- higher depletion, depreciation and amortization expense.
The increase in adjusted net earnings for the fourth quarter of
2013 from the comparable period in 2012 was primarily due to:
- higher SCO sales volumes in the Oil Sands Mining and Upgrading
segment;
- higher crude oil and NGLs sales volumes in the Offshore Africa
segment; and
- the impact of a weaker Canadian dollar relative to the US
dollar;
partially offset by:
- lower crude oil and NGLs sales volumes in the North America
segment.
The decrease in adjusted net earnings for the fourth quarter of
2013 from the third quarter of 2013 was primarily due to:
- lower North America crude oil and NGLs netbacks;
- lower crude oil and NGLs sales volumes in the North America
segment; and
- lower realized SCO prices;
partially offset by:
- higher crude oil and NGLs sales volumes in the Offshore Africa
segment; and
- the impact of a weaker Canadian dollar relative to the US
dollar.
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, 2013
was $7,477 million compared with $6,013 million for the year ended
December 31, 2012. Cash flow from operations for the fourth quarter
of 2013 was $1,782 million compared with $1,548 million for the
fourth quarter of 2012 and $2,454 million for the third quarter of
2013. The fluctuations in cash flow from operations from the
comparable periods were primarily due to the factors noted above
relating to the fluctuations in adjusted net earnings, excluding
depletion, depreciation and amortization expense, as well as due to
the impact of cash taxes.
Total production before royalties for the year ended December
31, 2013 increased 3% to 671,162 BOE/d from 654,665 BOE/d for the
year ended December 31, 2012. Total production before royalties for
the fourth quarter of 2013 increased 3% to 677,242 BOE/d from
658,973 BOE/d for the fourth quarter of 2012, and decreased 4% from
702,938 BOE/d for the third quarter of 2013.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results
for the eight most recently completed quarters:
($ millions, except per common share Dec 31 Sep 30 Jun 30 Mar 31
amounts) 2013 2013 2013 2013
----------------------------------------------------------------------------
Product sales $ 4,330 $ 5,284 $ 4,230 $ 4,101
Net earnings $ 413 $ 1,168 $ 476 $ 213
Net earnings per common share
- basic $ 0.38 $ 1.07 $ 0.44 $ 0.19
- diluted $ 0.38 $ 1.07 $ 0.44 $ 0.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per common share Dec 31 Sep 30 Jun 30 Mar 31
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
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volatility in the quarterly net earnings over the eight most
recently completed quarters was primarily due to:
- Crude oil pricing - The impact of fluctuating demand,
inventory storage levels and geopolitical uncertainties on
worldwide benchmark pricing, the impact of the WCS Heavy
Differential from the West Texas Intermediate reference location at
Cushing, Oklahoma ("WTI") in North America and the impact of the
differential between WTI and Dated Brent benchmark pricing in the
North Sea and Offshore Africa.
- Natural gas pricing - The impact of fluctuations in both the
demand for natural gas and inventory storage levels, and the impact
of increased shale gas production in the US.
- Crude oil and NGLs sales volumes - Fluctuations in production
due to the cyclic nature of the Company's Primrose thermal
projects, the results from the Pelican Lake water and polymer flood
projects, the strong heavy crude oil drilling program, and the
impact of the turnaround/suspension and subsequent recommencement
of production at Horizon. Sales volumes also reflected fluctuations
due to timing of liftings and maintenance activities in the North
Sea and Offshore Africa.
- Natural gas sales volumes - Fluctuations in production due to
the Company's 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, and the turnaround/suspension
and subsequent recommencement of production at Horizon.
- Depletion, depreciation and amortization - Fluctuations due to
changes in sales volumes, proved reserves, asset retirement
obligations, finding and development costs associated with crude
oil and natural gas exploration, estimated future costs to develop
the Company's proved undeveloped reserves, the effect of the
planned decommissioning of the Murchison platform in the North Sea,
and the impact of the turnaround/suspension and subsequent
recommencement of production at Horizon.
- Share-based compensation - Fluctuations due to the
determination of fair market value based on the Black-Scholes
valuation model of the Company's share-based compensation
liability.
- Risk management - Fluctuations due to the recognition of gains
and losses from the mark-to-market and subsequent settlement of the
Company's risk management activities.
- Foreign exchange rates - Changes in the Canadian dollar
relative to the US dollar that impacted the realized price the
Company received for its crude oil and natural gas sales, as sales
prices are based predominately on US dollar denominated benchmarks.
Fluctuations in realized and unrealized foreign exchange gains and
losses are also recorded with respect to US dollar denominated
debt, partially offset by the impact of cross currency swap
hedges.
- Income tax expense - Fluctuations in income tax expense
include statutory tax rate and other legislative changes
substantively enacted in the various periods.
- Gains on corporate acquisition/disposition of properties -
Fluctuations due to the recognition of gains on corporate
acquisitions/dispositions in the third quarter of 2013.
BUSINESS ENVIRONMENT
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
WTI benchmark price
(US$/bbl) $ 97.50 $ 105.82 $ 88.20 $ 98.00 $ 94.19
Dated Brent benchmark
price (US$/bbl) $ 109.29 $ 110.35 $ 110.03 $ 108.62 $ 111.56
WCS blend differential
from WTI (US$/bbl) $ 32.21 $ 17.42 $ 18.15 $ 25.11 $ 21.05
WCS blend differential
from WTI (%) 33% 16% 21% 26% 22%
SCO price (US$/bbl) $ 88.37 $ 109.97 $ 91.90 $ 98.18 $ 92.59
Condensate benchmark price
(US$/bbl) $ 94.30 $ 103.83 $ 98.13 $ 101.67 $ 100.92
NYMEX benchmark price
(US$/MMBtu) $ 3.63 $ 3.60 $ 3.36 $ 3.67 $ 2.80
AECO benchmark price
(C$/GJ) $ 2.99 $ 2.68 $ 2.89 $ 3.00 $ 2.28
US/Canadian dollar average
exchange rate (US$) $ 0.9529 $ 0.9629 $ 1.0088 $ 0.9710 $ 1.0004
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commodity Prices
Crude oil sales contracts in the North America segment are
typically based on WTI benchmark pricing. WTI averaged US$98.00 per
bbl for the year ended December 31, 2013, an increase of 4% from
US$94.19 per bbl for the year ended December 31, 2012. WTI averaged
US$97.50 per bbl for the fourth quarter of 2013, an increase of 11%
from US$88.20 per bbl for the fourth quarter of 2012, and a
decrease of 8% from US$105.82 per bbl for the third quarter of
2013.
Crude oil sales contracts for the Company's North Sea and
Offshore Africa segments are typically based on Dated Brent
("Brent") pricing, which is representative of international markets
and overall world supply and demand. Brent averaged US$108.62 per
bbl for the year ended December 31, 2013, a decrease of 3% from
US$111.56 per bbl for the year ended December 31, 2012. Brent
averaged US$109.29 per bbl for the fourth quarter of 2013,
consistent with the comparable periods.
WTI and Brent pricing continued to reflect volatility in supply
and demand factors and geopolitical events. The Brent differential
from WTI tightened for the three months and year ended December 31,
2013 from the comparable periods in 2012 due to a continued
debottlenecking of logistical constraints from Cushing to the US
Gulf Coast. The Brent differential from WTI widened in the fourth
quarter of 2013 compared with the third quarter of 2013 due to
increased inventory levels at Cushing as well as upward pressure on
Brent pricing.
The WCS Heavy Differential averaged 26% for the year ended
December 31, 2013 compared with 22% for the year ended December 31,
2012. The WCS Heavy Differential averaged 33% for the fourth
quarter of 2013 compared with 21% for the fourth quarter of 2012,
and 16% for the third quarter of 2013. The WCS Heavy Differential
widened in the fourth quarter of 2013 from the comparable periods
as a result of decreased heavy oil demand due to planned refinery
maintenance, pipeline logistical constraints and third party
unplanned refinery disruptions. To partially mitigate its exposure
to fluctuating heavy crude oil differentials, as at December 31,
2013, the Company entered into physical crude oil sales contracts
with weighted average fixed WCS differentials as follows: 8,000
bbl/d in the first quarter of 2014 at US$21.89 per bbl; 9,000 bbl/d
in the second quarter of 2014 at US$21.93 per bbl; and 10,000 bbl/d
in the third and fourth quarters of 2014 at US$20.81 per bbl.
Subsequent to December 31, 2013, the WCS Heavy Differential
narrowed in January 2014 to average US$29.17 per bbl and in
February 2014 to average US$19.14 per bbl. The WCS Heavy
Differentials are directionally tightening due to increased demand
as a result of third party refinery expansion and higher refinery
utilization.
The SCO price averaged US$98.18 per bbl for the year ended
December 31, 2013, an increase of 6% from US$92.59 per bbl for the
year ended December 31, 2012. The SCO price averaged US$88.37 per
bbl for the fourth quarter of 2013, a decrease of 4% from US$91.90
per bbl for the fourth quarter of 2012, and a decrease of 20% from
US$109.97 per bbl for the third quarter of 2013. The fluctuations
in SCO pricing for the three months and year ended December 31,
2013 from the comparable periods were primarily due to demand
fluctuations as well as movements in WTI benchmark pricing.
The WCS Heavy Differential is expected to continue to reflect
seasonal demand fluctuations, changes in transportation logistics,
and refinery utilization and shutdowns.
NYMEX natural gas prices averaged US$3.67 per MMBtu for the year
ended December 31, 2013, an increase of 31% from US$2.80 per MMBtu
for the year ended December 31, 2012. NYMEX natural gas prices
averaged US$3.63 per MMBtu for the fourth quarter of 2013, an
increase of 8% from US$3.36 per MMBtu for the fourth quarter of
2012, and an increase of 1% from US$3.60 per MMBtu for the third
quarter of 2013.
AECO natural gas prices for the year ended December 31, 2013
averaged $3.00 per GJ, an increase of 32% from $2.28 per GJ for the
year ended December 31, 2012. AECO natural gas prices for the
fourth quarter of 2013 averaged $2.99 per GJ, an increase of 3%
from $2.89 per GJ for the fourth quarter of 2012, and an increase
of 12% from $2.68 per GJ for the third quarter of 2013.
During the fourth quarter of 2013, natural gas prices continued
to recover from the low pricing levels in 2012. Natural gas prices
increased for the three months and year ended December 31, 2013
from the comparable periods in 2012 due to a return to normal
natural gas storage levels. Natural gas prices increased for the
fourth quarter of 2013 from the third quarter of 2013 due to
increased winter weather related natural gas demand and changes in
third party short-term tolling arrangements.
DAILY PRODUCTION, before royalties
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America -
Exploration and
Production 332,231 365,529 351,983 343,699 326,829
North America - Oil Sands
Mining and Upgrading 112,273 111,959 83,079 100,284 86,077
North Sea 20,155 15,522 19,140 18,334 19,824
Offshore Africa 13,379 16,172 15,762 15,923 18,648
----------------------------------------------------------------------------
478,038 509,182 469,964 478,240 451,378
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,165 1,136 1,113 1,130 1,198
North Sea 7 4 1 4 2
Offshore Africa 23 23 20 24 20
----------------------------------------------------------------------------
1,195 1,163 1,134 1,158 1,220
----------------------------------------------------------------------------
Total barrels of oil
equivalent (BOE/d) 677,242 702,938 658,973 671,162 654,665
----------------------------------------------------------------------------
Product mix
Light and medium crude oil
and NGLs 16% 14% 15% 15% 16%
Pelican Lake heavy crude
oil 7% 6% 5% 7% 6%
Primary heavy crude oil 20% 20% 20% 20% 19%
Bitumen (thermal oil) 11% 16% 18% 14% 15%
Synthetic crude oil 17% 16% 13% 15% 13%
Natural gas 29% 28% 29% 29% 31%
----------------------------------------------------------------------------
Percentage of product
sales (1) (2) (excluding
Midstream revenue)
Crude oil and NGLs 89% 93% 90% 90% 91%
Natural gas 11% 7% 10% 10% 9%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of blending costs and excluding risk management
activities.
(2) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.
DAILY PRODUCTION, net of royalties
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America -
Exploration and
Production 285,594 299,194 305,577 287,428 273,374
North America - Oil Sands
Mining and Upgrading 106,358 104,627 79,691 95,098 82,171
North Sea 20,106 15,481 19,096 18,279 19,772
Offshore Africa 11,351 11,998 10,358 12,973 13,628
----------------------------------------------------------------------------
423,409 431,300 414,722 413,778 388,945
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,101 1,109 1,047 1,080 1,171
North Sea 7 4 1 4 2
Offshore Africa 19 18 16 20 17
----------------------------------------------------------------------------
1,127 1,131 1,064 1,104 1,190
----------------------------------------------------------------------------
Total barrels of oil
equivalent (BOE/d) 611,245 619,800 592,080 597,835 587,246
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's business approach is to maintain large project
inventories and production diversification among each of the
commodities it produces; namely light and medium crude oil and
NGLs, primary heavy crude oil, Pelican Lake heavy crude oil,
bitumen (thermal oil), SCO and natural gas.
Crude oil and NGLs production for the year ended December 31,
2013 increased 6% to 478,240 bbl/d from 451,378 bbl/d for the year
ended December 31, 2012. Crude oil and NGLs production for the
fourth quarter of 2013 increased 2% to 478,038 bbl/d from 469,964
bbl/d for the fourth quarter of 2012 and decreased 6% from 509,182
bbl/d for the third quarter of 2013. The increase in production for
the year ended December 31, 2013 from the comparable period in 2012
was primarily due to strong production in Horizon and Pelican Lake
and the impact of the drilling program. The increase in production
for the fourth quarter of 2013 from the comparable period in 2012
reflected the impact of strong production in Horizon, which was
partially offset by lower production from the Company's cyclic
thermal operations in the latter half of 2013. The decrease in
production for the fourth quarter of 2013 from the third quarter of
2013 was primarily due to decreased production from the Company's
cyclic thermal operations, the impact of a third party fuel gas
supply interruption in the Woodenhouse area, and a strategic
temporary reduction of heavy oil production in the fourth quarter
of 2013 due to a wider WCS Heavy Differential. Crude oil and NGLs
production in the fourth quarter of 2013 was within the Company's
previously issued guidance of 474,000 to 513,000 bbl/d.
Natural gas production for the year ended December 31, 2013
decreased 5% to 1,158 MMcf/d from 1,220 MMcf/d for the year ended
December 31, 2012. Natural gas production for the fourth quarter of
2013 increased 5% to 1,195 MMcf/d from 1,134 MMcf/d for the fourth
quarter of 2012 and increased 3% from 1,163 MMcf/d for the third
quarter of 2013. The decrease in natural gas production for the
year ended December 31, 2013 from the comparable period 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. The increase in
natural gas production for the fourth quarter of 2013 from the
comparable periods was primarily a result of the completion of the
Septimus drilling program and plant facility expansion in the third
quarter, as well as the completion of a minor acquisition during
the fourth quarter of 2013. Natural gas production in the fourth
quarter of 2013 was within the Company's previously issued guidance
of 1,195 to 1,205 MMcf/d.
For 2014, annual production guidance is targeted to average
between 521,000 and 560,000 bbl/d of crude oil and NGLs and between
1,170 and 1,210 MMcf/d of natural gas. First quarter 2014
production guidance is targeted to average between 469,000 and
495,000 bbl/d of crude oil and NGLs and between 1,166 and 1,186
MMcf/d of natural gas.
North America - Exploration and Production
North America crude oil and NGLs production for the year ended
December 31, 2013 increased 5% to average 343,699 bbl/d from
326,829 bbl/d for the year ended December 31, 2012. For the fourth
quarter of 2013, crude oil and NGLs production decreased 6% to
average 332,231 bbl/d compared with 351,983 bbl/d for the fourth
quarter of 2012 and decreased 9% from 365,529 bbl/d for the third
quarter of 2013. The increase in crude oil and NGLs production for
the year ended December 31, 2013 from the comparable period was
primarily due to strong production in Pelican Lake and the impact
of the drilling program. The decrease in production for the fourth
quarter of 2013 from the comparable periods was primarily due to
the decrease in production from the Company's cyclic thermal
operations, the impact of a third party fuel gas supply
interruption in the Woodenhouse area and a strategic temporary
reduction of heavy oil production in the fourth quarter of 2013 due
to a wider WCS Heavy Differential. Fourth quarter 2013 production
of crude oil and NGLs was within the Company's previously issued
guidance of 332,000 to 362,000 bbl/d. First quarter 2014 production
guidance is targeted to average between 335,000 and 351,000 bbl/d
for crude oil and NGLs.
North America natural gas production for the year ended December
31, 2013 decreased 6% to 1,130 MMcf/d compared with 1,198 MMcf/d
for the year ended December 31, 2012. Natural gas production
increased 5% to 1,165 MMcf/d for the fourth quarter of 2013
compared with 1,113 MMcf/d in the fourth quarter of 2012 and
increased 3% from 1,136 MMcf/d for the third quarter of 2013. The
decrease in natural gas production for the year ended December 31,
2013 from the comparable period 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. The increase in natural gas
production for the fourth quarter of 2013 from the comparable
periods was primarily a result of the completion of the Septimus
drilling program and plant facility expansion in the third quarter,
as well as the completion of a minor acquisition during the fourth
quarter of 2013.
North America - Oil Sands Mining and Upgrading
Production averaged 100,284 bbl/d for the year ended December
31, 2013 compared with 86,077 bbl/d for the year ended December 31,
2012. For the fourth quarter of 2013, SCO production averaged
112,273 bbl/d compared with 83,079 bbl/d for the fourth quarter of
2012 and 111,959 bbl/d for the third quarter of 2013. Production
increased for the three months and year ended December 31, 2013
from the comparable periods in 2012, reflecting a continued focus
on reliable and efficient operations, and the impact of the
successful completion of Horizon's planned maintenance turnaround
in May 2013. Production of SCO was within the Company's previously
issued guidance of 110,000 to 115,000 bbl/d for the fourth quarter
of 2013. First quarter 2014 production guidance is targeted to
average between 108,000 and 115,000 bbl/d.
North Sea
North Sea crude oil production for the year ended December 31,
2013 decreased 8% to 18,334 bbl/d from 19,824 bbl/d for the year
ended December 31, 2012. Fourth quarter 2013 North Sea crude oil
production increased 5% to 20,155 bbl/d from 19,140 bbl/d for the
fourth quarter of 2012, and increased 30% from 15,522 bbl/d for the
third quarter of 2013. The decrease in production for the year
ended December 31, 2013 from the comparable period was primarily
due to natural field declines, turnaround activities and a previous
reduction in drilling activities as a result of an increase in the
UK corporate income tax rate in 2011. The increase in production
for the fourth quarter of 2013 from the comparable period in 2012
was due to temporary shut ins of the third-party operated pipeline
to the Sullom Voe Terminal, in 2012, which caused all Ninian and
associated fields to be shut in for a portion of the fourth quarter
of 2012. The increase in production for the fourth quarter of 2013
from the third quarter of 2013 was primarily a result of the
successful completion of planned turnarounds during the third
quarter of 2013.
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 is currently
undergoing repairs and is targeted to be back in the field early in
the third quarter of 2014. The associated repair costs, net of
insurance recoveries, are not expected to be significant. The
financial impact to operations has been partially mitigated through
receipt of business interruption insurance proceeds.
Offshore Africa
Offshore Africa crude oil production decreased 15% to 15,923
bbl/d for the year ended December 31, 2013 from 18,648 bbl/d for
the year ended December 31, 2012. Fourth quarter 2013 crude oil
production averaged 13,379 bbl/d, decreasing 15% from 15,762 bbl/d
for the fourth quarter of 2012 and decreasing 17% from 16,172 bbl/d
for the third quarter of 2013. The decrease in production volumes
for the three months and year ended December 31, 2013 from the
comparable periods was due to natural field declines and a
temporary shut in of the Baobab field in December 2013 due to a
FPSO mooring line failure. Turnaround activities were advanced into
this timeframe and production in the Baobab field was reinstated in
late January 2014. The Company plans to perform permanent repairs
on the mooring lines in March 2014.
International Guidance
The Company's North Sea and Offshore Africa fourth quarter 2013
crude oil production was 33,534 bbl/d and was within the Company's
previously issued guidance of 32,000 to 36,000 bbl/d. First quarter
2014 production guidance is targeted to average between 26,000 and
29,000 bbl/d of crude oil.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when
title transfers to the customer and delivery has taken place.
Revenue has not been recognized on crude oil volumes that were
stored in various tanks, pipelines, or FPSOs, as follows:
------------------------------------
Dec 31 Sep 30 Dec 31
(bbl) 2013 2013 2012
----------------------------------------------------------------------------
North America - Exploration and
Production 830,673 499,490 643,758
North America - Oil Sands Mining and
Upgrading (SCO) 1,550,857 1,172,723 993,627
North Sea 385,073 533,155 77,018
Offshore Africa 185,476 1,858,081 1,036,509
----------------------------------------------------------------------------
2,952,079 4,063,449 2,750,912
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
Sales price (2) (3) $ 69.38 $ 89.24 $ 66.55 $ 73.81 $ 72.44
Transportation 1.84 2.38 2.32 2.22 2.20
----------------------------------------------------------------------------
Realized sales price, net
of transportation 67.54 86.86 64.23 71.59 70.24
Royalties 8.82 15.20 8.59 11.13 10.67
Production expense 18.59 15.90 15.32 17.14 16.11
----------------------------------------------------------------------------
Netback $ 40.13 $ 55.76 $ 40.32 $ 43.32 $ 43.46
----------------------------------------------------------------------------
Natural gas ($/Mcf) (1)
Sales price (2) (3) $ 3.62 $ 3.15 $ 3.42 $ 3.58 $ 2.70
Transportation 0.28 0.27 0.26 0.28 0.26
----------------------------------------------------------------------------
Realized sales price, net
of transportation 3.34 2.88 3.16 3.30 2.44
Royalties 0.21 0.10 0.21 0.18 0.09
Production expense 1.37 1.38 1.43 1.42 1.31
----------------------------------------------------------------------------
Netback $ 1.76 $ 1.40 $ 1.52 $ 1.70 $ 1.04
----------------------------------------------------------------------------
Barrels of oil equivalent
($/BOE) (1)
Sales price (2) (3) $ 53.30 $ 67.09 $ 51.97 $ 56.46 $ 52.85
Transportation 1.83 2.18 2.14 2.10 2.04
----------------------------------------------------------------------------
Realized sales price, net
of transportation 51.47 64.91 49.83 54.36 50.81
Royalties 6.23 10.35 6.22 7.74 7.07
Production expense 15.04 13.36 13.11 14.24 13.14
----------------------------------------------------------------------------
Netback $ 30.20 $ 41.20 $ 30.50 $ 32.38 $ 30.60
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
(2) Net of blending costs and excluding risk management
activities.
(3) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.
PRODUCT PRICES - EXPLORATION AND PRODUCTION
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)(2) (3)
North America $ 62.70 $ 87.62 $ 62.68 $ 69.90 $ 67.93
North Sea $ 113.84 $ 117.30 $ 109.47 $ 112.46 $ 111.90
Offshore Africa $ 108.25 $ 119.48 $ 97.97 $ 110.21 $ 111.18
Company average $ 69.38 $ 89.24 $ 66.55 $ 73.81 $ 72.44
Natural gas ($/Mcf) (1)(2)
(3)
North America $ 3.46 $ 3.00 $ 3.30 $ 3.43 $ 2.57
North Sea $ 5.05 $ 6.12 $ 3.96 $ 5.69 $ 5.14
Offshore Africa $ 11.13 $ 10.47 $ 10.39 $ 10.45 $ 10.31
Company average $ 3.62 $ 3.15 $ 3.42 $ 3.58 $ 2.70
Company average ($/BOE)
(1)(2) (3) $ 53.30 $ 67.09 $ 51.97 $ 56.46 $ 52.85
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
(2) Net of blending costs and excluding risk management
activities.
(3) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.
North America
North America realized crude oil prices increased 3% to average
$69.90 per bbl for the year ended December 31, 2013 from $67.93 per
bbl for the year ended December 31, 2012. North America realized
crude oil prices averaged $62.70 per bbl for the fourth quarter of
2013 and were comparable with $62.68 per bbl for the fourth quarter
of 2012 and decreased 28% compared with $87.62 per bbl for the
third quarter of 2013. The increase in realized crude oil prices
for the year ended December 31, 2013 from the comparable period was
due to higher WTI benchmark pricing and the impact of a weaker
Canadian dollar relative to the US dollar. The decrease in realized
crude oil prices for the fourth quarter of 2013 from the third
quarter for 2013 was due to lower benchmark WTI pricing and the
widening of the WCS Heavy Differential, partially offset by the
impact of a weaker Canadian dollar relative to the US dollar. The
Company continues to focus on its crude oil blending marketing
strategy and in the fourth quarter of 2013 contributed
approximately 168,000 bbl/d of heavy crude oil blends to the WCS
stream.
North America realized natural gas prices increased 33% to
average $3.43 per Mcf for the year ended December 31, 2013 from
$2.57 per Mcf for the year ended December 31, 2012. North America
realized natural gas prices increased 5% to average $3.46 per Mcf
for the fourth quarter of 2013 compared with $3.30 per Mcf in the
fourth quarter of 2012, and increased 15% compared with $3.00 per
Mcf for the third quarter of 2013. The increase in realized natural
gas prices for the three months and year ended December 31, 2013
from the comparable periods in 2012 was primarily due to a return
to normal gas storage levels. The increase in realized natural gas
prices for the fourth quarter of 2013 from the third quarter of
2013 was primarily due to seasonal weather related natural gas
demand and changes in third party short-term tolling
arrangements.
Comparisons of the prices received in North America Exploration
and Production by product type were as follows:
------------------------------------
Dec 31 Sep 30 Dec 31
(Quarterly Average) 2013 2013 2012
----------------------------------------------------------------------------
Wellhead Price(1) (2) (3)
Light and medium crude oil and NGLs
($/bbl) $ 70.91 $ 83.10 $ 70.20
Pelican Lake heavy crude oil ($/bbl) $ 60.19 $ 90.32 $ 65.12
Primary heavy crude oil ($/bbl) $ 61.75 $ 89.76 $ 62.02
Bitumen (thermal oil) ($/bbl) $ 57.97 $ 86.68 $ 58.69
Natural gas ($/Mcf) $ 3.46 $ 3.00 $ 3.30
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
(2) Net of blending costs and excluding risk management
activities.
(3) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.
North Sea
North Sea realized crude oil prices averaged $112.46 per bbl for
the year ended December 31, 2013 and were comparable with $111.90
per bbl for the year ended December 31, 2012. Realized crude oil
prices increased 4% to average $113.84 per bbl for the fourth
quarter of 2013 from $109.47 per bbl for the fourth quarter of
2012, and decreased 3% from $117.30 per bbl for the third quarter
of 2013. The fluctuations in realized crude oil prices for the
three months and year ended December 31, 2013 from the comparable
periods reflected movements in Brent benchmark pricing, the timing
of liftings, and the impact of a weaker Canadian dollar relative to
the US dollar.
Offshore Africa
Offshore Africa realized crude oil prices averaged $110.21 per
bbl for the year ended December 31, 2013 and were comparable with
$111.18 per bbl for the year ended December 31, 2012. Realized
crude oil prices increased 10% to average $108.25 per bbl for the
fourth quarter of 2013 from $97.97 per bbl for the fourth quarter
of 2012, and decreased 9% from $119.48 per bbl for the third
quarter of 2013. The fluctuations in realized crude oil prices for
the three months and year ended December 31, 2013 from the
comparable periods reflected movements in Brent benchmark pricing,
the timing of liftings, and the impact of a weaker Canadian dollar
relative to the US dollar.
ROYALTIES - EXPLORATION AND PRODUCTION
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
North America $ 8.66 $ 15.65 $ 7.93 $ 11.30 $ 10.33
North Sea $ 0.28 $ 0.31 $ 0.25 $ 0.33 $ 0.29
Offshore Africa $ 16.41 $ 30.83 $ 33.59 $ 18.18 $ 29.46
Company average $ 8.82 $ 15.20 $ 8.59 $ 11.13 $ 10.67
Natural gas ($/Mcf) (1)
North America $ 0.17 $ 0.06 $ 0.18 $ 0.14 $ 0.06
Offshore Africa $ 2.04 $ 2.06 $ 1.74 $ 1.83 $ 1.77
Company average $ 0.21 $ 0.10 $ 0.21 $ 0.18 $ 0.09
Company average ($/BOE)
(1) $ 6.23 $ 10.35 $ 6.22 $ 7.74 $ 7.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2013 compared with the year ended December 31,
2012 reflected movements in benchmark commodity prices and the
fluctuations of the WCS Heavy Differential.
Crude oil and NGLs royalties averaged approximately 17% of
product sales in 2013 compared with 16% in 2012. Crude oil and NGLs
royalties averaged approximately 14% of product sales for the
fourth quarter of 2013 compared with 13% for the fourth quarter of
2012 and 18% for the third quarter of 2013. The decrease in
royalties in the fourth quarter of 2013 from the third quarter of
2013 was primarily due to the decrease in realized crude oil
prices. Crude oil and NGLs royalties per bbl are anticipated to
average 18% to 20% of product sales for 2014.
Natural gas royalties averaged approximately 5% of product sales
in 2013 compared with 3% in 2012. Natural gas royalties averaged
approximately 5% of product sales for the fourth quarter of 2013
compared with 6% for the fourth quarter of 2012 and 2% for the
third quarter of 2013. The fluctuations in natural gas royalty
rates compared with the comparable periods primarily reflected
movements in realized natural gas prices. Natural gas royalties are
anticipated to average 7% to 8% of product sales for 2014.
Offshore Africa
Under the terms of the various Production Sharing Contracts,
royalty rates fluctuate based on realized commodity pricing,
capital and operating costs, the status of payouts, and the timing
of liftings from each field.
Royalty rates as a percentage of product sales averaged
approximately 17% in 2013 compared with 26% in 2012. Royalty rates
as a percentage of product sales averaged approximately 15% for the
fourth quarter of 2013 compared with 32% for the fourth quarter of
2012 and 24% for the third quarter of 2013. The fluctuations in
royalties from the comparable periods in 2012 were due to
adjustments to royalties.
Offshore Africa royalty rates are anticipated to average 4.5% to
6.5% of product sales for 2014.
PRODUCTION EXPENSE - EXPLORATION AND PRODUCTION
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
North America $ 14.46 $ 13.04 $ 12.79 $ 14.20 $ 13.40
North Sea $ 65.41 $ 78.66 $ 54.41 $ 66.19 $ 53.53
Offshore Africa $ 29.31 $ 25.13 $ 22.14 $ 25.32 $ 23.11
Company average $ 18.59 $ 15.90 $ 15.32 $ 17.14 $ 16.11
Natural gas ($/Mcf) (1)
North America $ 1.32 $ 1.33 $ 1.40 $ 1.39 $ 1.28
North Sea $ 4.81 $ 5.79 $ 3.58 $ 4.67 $ 3.75
Offshore Africa $ 2.73 $ 2.82 $ 3.19 $ 2.53 $ 2.27
Company average $ 1.37 $ 1.38 $ 1.43 $ 1.42 $ 1.31
Company average ($/BOE)
(1) $ 15.04 $ 13.36 $ 13.11 $ 14.24 $ 13.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2013 increased 6% to $14.20 per bbl from $13.40
per bbl for the year ended December 31, 2012. North America crude
oil and NGLs production expense for the fourth quarter of 2013
increased 13% to $14.46 per bbl from $12.79 per bbl for the fourth
quarter of 2012 and increased 11% from $13.04 per bbl for the third
quarter of 2013. The increase in production expense for the three
months and year ended December 31, 2013 from the comparable periods
was primarily the result of higher electricity costs, as well as
higher servicing costs related to heavy oil activities. North
America crude oil and NGLs production expense was slightly higher
than the Company's previously issued guidance of $12.00 to $14.00
per bbl, and is anticipated to average $12.50 to $14.50 per bbl for
2014.
North America natural gas production expense for the year ended
December 31, 2013 increased 9% to $1.39 per Mcf from $1.28 per Mcf
for the year ended December 31, 2012. North America natural gas
production expense for the fourth quarter of 2013 decreased 6% to
$1.32 per Mcf from $1.40 per Mcf for the fourth quarter of 2012,
and was comparable with the third quarter of 2013. Natural gas
production expense increased for the year ended December 31, 2013
from the year ended December 31, 2012 primarily due to lower
production volumes related to the strategic reduction in natural
gas activity. Natural gas production expense decreased for the
fourth quarter of 2013 from the comparable periods due to increased
production. North America natural gas production expense was within
the Company's previously issued guidance of $1.35 to $1.40 per Mcf,
and is anticipated to average $1.35 to $1.45 per Mcf for 2014.
North Sea
North Sea crude oil production expense for the year ended
December 31, 2013 increased 24% to $66.19 per bbl from $53.53 per
bbl for the year ended December 31, 2012. North Sea crude oil
production expense for the fourth quarter of 2013 increased 20% to
$65.41 per bbl from $54.41 per bbl for the fourth quarter of 2012
and decreased 17% from $78.66 per bbl for the third quarter of
2013. Production expense increased on a per barrel basis for the
three months and year ended December 31, 2013 from the comparable
periods in 2012 due to production declines on relatively fixed
costs. The decrease for the fourth quarter of 2013 from the third
quarter of 2013 was due to the impacts of turnaround activities and
higher production volumes on a relatively fixed cost structure.
North Sea crude oil production expense was slightly higher than the
Company's previously issued guidance of $62.00 to $66.00 per bbl.
Production expense is anticipated to average $52.00 to $56.00 per
bbl for 2014 due to new drilling activities which are expected to
result in additional production from the Ninian fields, and as the
Banff FPSO is targeted to return to service early in the third
quarter of 2014.
Offshore Africa
Offshore Africa crude oil production expense for the year ended
December 31, 2013 increased 10% to $25.32 per bbl from $23.11 per
bbl for the year ended December 31, 2012. Offshore Africa crude oil
production expense for the fourth quarter of 2013 averaged $29.31
per bbl, an increase of 32% from $22.14 per bbl for the fourth
quarter of 2012, and an increase of 17% from $25.13 per bbl for the
third quarter of 2013. Production expense increased for the three
months and year ended December 31, 2013 from the comparable periods
in 2012 as a result of production declines on relatively fixed
costs and the timing of liftings from various fields, which have
different cost structures. The increase for the fourth quarter of
2013 from the third quarter of 2013 was due to timing of liftings
from various fields. Offshore Africa crude oil production expense
was below the Company's previously issued guidance of $27.00 to
$30.00 per bbl, and is anticipated to average $38.50 to $42.50 per
bbl for 2014 due to timing of liftings from various fields, which
have different cost structures, as well as due to lower
production.
DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND
PRODUCTION
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Expense ($ millions) $ 1,133 $ 1,089 $ 1,097 $ 4,254 $ 3,874
$/BOE (1) $ 21.20 $ 20.33 $ 20.66 $ 20.38 $ 18.65
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 31, 2013 from the
comparable periods primarily due to the effect of the planned
cessation of production and decommissioning of the Murchison
platform in the North Sea, fluctuations in sales volumes and higher
overall future development costs.
ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND
PRODUCTION
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Expense ($ millions) $ 38 $ 32 $ 30 $ 137 $ 119
$/BOE (1) $ 0.71 $ 0.61 $ 0.56 $ 0.66 $ 0.57
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
Asset retirement obligation accretion expense represents the
increase in the carrying amount of the asset retirement obligation
due to the passage of time.
OPERATING HIGHLIGHTS - OIL SANDS MINING AND UPGRADING
OPERATIONS UPDATE
The Company continues to focus on reliable and efficient
operations. During the fourth quarter of 2013, operating
performance continued to be strong, leading to production of
112,273 bbl/d, which was within stated guidance.
PRODUCT PRICES, ROYALTIES AND TRANSPORTATION - OIL SANDS MINING
AND UPGRADING
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($/bbl) (1) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
SCO sales price (2) $ 92.05 $ 114.19 $ 89.40 $ 100.75 $ 90.74
Bitumen value for royalty
purposes (3) $ 55.45 $ 82.78 $ 58.12 $ 65.48 $ 59.93
Bitumen royalties (4) $ 5.06 $ 6.82 $ 3.80 $ 5.11 $ 4.34
Transportation $ 1.51 $ 1.52 $ 2.06 $ 1.57 $ 1.83
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes excluding the period of turnaround/suspension of
production.
(2) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.
(3) Calculated as the quarterly average of the bitumen valuation
methodology price.
(4) Calculated based on actual bitumen royalties expensed during
the period; divided by the corresponding SCO sales volumes.
Realized SCO sales prices averaged $100.75 per bbl for the year
ended December 31, 2013, an increase of 11% compared with $90.74
per bbl for the year ended December 31, 2012. Realized SCO sales
prices averaged $92.05 per bbl for the fourth quarter of 2013, an
increase of 3% compared with $89.40 per bbl for the fourth quarter
of 2012 and an decrease of 19% compared with $114.19 per bbl for
the third quarter of 2013, reflecting benchmark pricing and
prevailing differentials.
CASH PRODUCTION COSTS - OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and
Upgrading production costs disclosed in the Company's unaudited
interim consolidated financial statements.
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Cash production costs $ 389 $ 407 $ 372 $ 1,567 $ 1,504
Less: costs incurred
during the period of
turnaround/suspension of
production - - - (104) (154)
----------------------------------------------------------------------------
Adjusted cash production
costs $ 389 $ 407 $ 372 $ 1,463 $ 1,350
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Adjusted cash production
costs, excluding natural
gas costs $ 362 $ 380 $ 342 $ 1,359 $ 1,254
Adjusted natural gas costs 27 27 30 104 96
----------------------------------------------------------------------------
Adjusted cash production
costs $ 389 $ 407 $ 372 $ 1,463 $ 1,350
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($/bbl) (1) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Adjusted cash production
costs, excluding natural
gas costs $ 36.31 $ 37.27 $ 45.31 $ 37.68 $ 39.79
Adjusted natural gas costs 2.74 2.63 3.96 2.89 3.04
----------------------------------------------------------------------------
Adjusted cash production
costs $ 39.05 $ 39.90 $ 49.27 $ 40.57 $ 42.83
----------------------------------------------------------------------------
Sales (bbl/d) (2) 108,163 110,750 81,936 98,757 86,153
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Adjusted cash production costs on a per unit basis were
based on sales volumes excluding the period of
turnaround/suspension of production.
(2) Sales volumes include the period of turnaround/suspension of
production.
Adjusted cash production costs averaged $40.57 per bbl for the
year ended December 31, 2013, a decrease of 5% compared with $42.83
per bbl for the year ended December 31, 2012. Adjusted cash
production costs for the fourth quarter of 2013 averaged $39.05 per
bbl, a decrease of 21% compared with $49.27 per bbl for the fourth
quarter of 2012 and a decrease of 2% compared with $39.90 per bbl
for the third quarter of 2013 primarily reflecting the impact of
strong production volumes on a relatively fixed cost structure.
Cash production costs are anticipated to average $36.00 to $39.00
per bbl for 2014.
DEPLETION, DEPRECIATION AND AMORTIZATION - OIL SANDS MINING AND
UPGRADING
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Depletion, depreciation
and amortization $ 137 $ 167 $ 114 $ 582 $ 447
Less: depreciation
incurred during the
period of
turnaround/suspension of
production - - - (79) (6)
----------------------------------------------------------------------------
Adjusted depletion,
depreciation and
amortization $ 137 $ 167 $ 114 $ 503 $ 441
----------------------------------------------------------------------------
$/bbl (1) $ 13.75 $ 16.40 $ 15.12 $ 13.95 $ 13.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes excluding the period of turnaround/suspension of
production.
Depletion, depreciation and amortization expense reflected the
impact of fluctuations in sales volumes and minor asset
derecognitions.
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) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Expense $ 8 $ 9 $ 8 $ 34 $ 32
$/bbl (1) $ 0.85 $ 0.83 $ 1.06 $ 0.94 $ 1.01
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Revenue $ 26 $ 28 $ 26 $ 110 $ 93
Production expense 8 9 8 34 29
----------------------------------------------------------------------------
Midstream cash flow 18 19 18 76 64
Depreciation 2 2 2 8 7
Equity loss from joint
venture 1 1 3 4 9
----------------------------------------------------------------------------
Segment earnings before
taxes $ 15 $ 16 $ 13 $ 64 $ 48
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream operating results were consistent with the comparable
periods.
The Company has a 50% interest in the North West Redwater
Partnership ("Redwater Partnership"). Redwater Partnership has
entered into agreements to construct and operate a 50,000 barrel
per day bitumen upgrader and refinery (the "Project") under
processing agreements that target to process 12,500 barrels per day
of bitumen feedstock for the Company and 37,500 barrels per day of
bitumen feedstock for the Alberta Petroleum Marketing Commission
("APMC"), an agent of the Government of Alberta, under a 30 year
fee-for-service tolling agreement. During 2012, the Project
received board sanction from Redwater Partnership and its
partners.
As at December 31, 2013, Redwater Partnership had interim
borrowings of $702 million under credit facilities totaling $1,200
million with original maturities no later than December 2017. These
facilities are secured by a floating charge on the assets of
Redwater Partnership with a mandatory repayment required from
future financing proceeds. At maturity, under its processing
agreement, the Company would be obligated to pay its 25% pro rata
share of any shortfall.
In December 2013, Redwater Partnership, the Company and APMC
agreed in principle to amend certain terms of the processing
agreements. In conjunction with these amendments, the Company,
along with APMC, each committed to provide additional funding up to
$350 million to attain Project completion based on the revised
Project cost estimate of approximately $8,500 million. The
additional funding is to be in the form of subordinated debt
bearing interest at prime plus 6%, which is anticipated to form
part of the equity toll. Should final Project costs exceed the
revised cost estimate, the Company and APMC have agreed, subject to
the Company being able to meet certain funding conditions, to fund
any shortfall in available third party commercial lending required
to attain Project completion.
Redwater Partnership has entered into various agreements related
to the engineering, procurement and construction of the Project.
These contracts can be cancelled by Redwater Partnership upon
notice without penalty, subject to the costs incurred up to and in
respect of the cancellation.
Subsequent to December 31, 2013, the credit facility maturity
date was amended to mature on November 28, 2014. At maturity or at
such later date as mutually agreed to by the lenders and Redwater
Partnership, the Company will be obligated to repay its 25% pro
rata share of any amount outstanding under the facility. As at
March 4, 2014, interim borrowings under the facilities were $857
million.
ADMINISTRATION EXPENSE
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Expense $ 93 $ 82 $ 64 $ 335 $ 270
$/BOE (1) $ 1.47 $ 1.28 $ 1.07 $ 1.37 $ 1.13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
Administration expense for the three months and year ended
December 31, 2013 increased from the comparable periods in 2012
primarily due to higher staffing and general corporate costs.
SHARE-BASED COMPENSATION
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Expense (recovery) $ 65 $ 48 $ (41) $ 135 $ (214)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $135 million share-based compensation
expense for the year ended December 31, 2013, primarily as a result
of remeasurement of the fair value of outstanding stock options at
the end of the year related to an increase in the Company's share
price, together with the impact of normal course graded vesting of
stock options granted in prior periods and the impact of vested
stock options exercised or surrendered during the year. For the
year ended December 31, 2013, the Company capitalized $25 million
of share-based compensation expense to property, plant and
equipment in the Oil Sands Mining and Upgrading segment (December
31, 2012 - $12 million recovery).
For the year ended December 31, 2013, the Company paid $4
million for stock options surrendered for cash settlement (December
31, 2012 - $7 million).
INTEREST AND OTHER FINANCING EXPENSE
Three Months Ended Year Ended
--------------------------------------------------
($ millions, except per Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
BOE amounts) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Expense, gross $ 113 $ 116 $ 115 $ 454 $ 462
Less: capitalized interest 53 46 32 175 98
----------------------------------------------------------------------------
Expense, net $ 60 $ 70 $ 83 $ 279 $ 364
$/BOE (1) $ 0.94 $ 1.10 $ 1.37 $ 1.14 $ 1.52
Average effective interest
rate 4.4% 4.3% 4.8% 4.4% 4.8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
Gross interest and other financing expense for the three months
and year ended December 31, 2013 was consistent with the comparable
periods. Capitalized interest of $175 million for the year ended
December 31, 2013 was related to the Horizon Phase 2/3 expansion
and the Kirby Thermal Oil Sands Project.
The Company's average effective interest rate for the three
months and year ended December 31, 2013 decreased from the
comparable periods in 2012 primarily due to the repayment of $400
million of 4.50% medium-term notes and US$400 million of 5.15%
notes during the first quarter of 2013 and US$350 million of 5.45%
notes in the fourth quarter of 2012 as well as due to an increase
in the utilization of the lower cost US commercial paper program
that was implemented in March 2013. The Company's average effective
interest rate for the fourth quarter of 2013 was comparable with
the third quarter of 2013.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to
manage its commodity price, interest rate and foreign currency
exposures. These derivative financial instruments are not intended
for trading or speculative purposes.
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments $ 5 $ 39 $ 19 $ 44 $ 65
Foreign currency contracts (41) (17) (27) (160) 97
----------------------------------------------------------------------------
Realized (gain) loss (36) 22 (8) (116) 162
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments (10) 57 29 17 3
Natural gas financial
instruments (5) 8 - 3 -
Foreign currency contracts (15) 56 (21) 19 (45)
----------------------------------------------------------------------------
Unrealized (gain) loss (30) 121 8 39 (42)
----------------------------------------------------------------------------
Net (gain) loss $ (66) $ 143 $ - $ (77) $ 120
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Complete details related to outstanding derivative financial
instruments at December 31, 2013 are disclosed in note 14 to the
Company's unaudited interim consolidated financial statements.
The Company recorded a net unrealized loss of $39 million ($32
million after-tax) on its risk management activities for the year
ended December 31, 2013, including an unrealized gain of $30
million ($26 million after-tax) for the fourth quarter of 2013
(September 30, 2013 - unrealized loss of $121 million; $99 million
after-tax; December 31, 2012 - unrealized loss of $8 million; $4
million after-tax).
FOREIGN EXCHANGE
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Net realized loss (gain) $ 3 $ 12 $ (196) $ (16) $ (178)
Net unrealized loss (gain)
(1) 111 (75) 254 226 129
----------------------------------------------------------------------------
Net loss (gain) $ 114 $ (63) $ 58 $ 210 $ (49)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2013 was primarily due to foreign exchange rate
fluctuations on settlement of working capital items denominated in
US dollars or UK pounds sterling and the repayment of US$400
million of 5.15% notes in the first quarter of 2013. The net
unrealized foreign exchange loss for the year ended December 31,
2013 was primarily related to the impact of a weaker Canadian
dollar with respect to remaining US dollar debt and the reversal of
the life-to-date unrealized foreign exchange gain on the repayment
of US$400 million of 5.15% notes in the first quarter of 2013. The
net unrealized loss (gain) for each of the periods presented
included the impact of cross currency swaps (three months ended
December 31, 2013 - unrealized gain of $85 million, September 30,
2013 - unrealized loss of $55 million, December 31, 2012 -
unrealized gain of $27 million; year ended December 31, 2013 -
unrealized gain of $165 million; December 31, 2012 - unrealized
loss of $53 million). The US/Canadian dollar exchange rate at
December 31, 2013 was US$0.9402 (September 30, 2013 - US$0.9723;
December 31, 2012 - US$1.0051).
INCOME TAXES
Three Months Ended Year Ended
--------------------------------------------------
($ millions, except income Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
tax rates) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
North America (1) $ 133 $ 178 $ 68 $ 544 $ 366
North Sea 5 - 29 23 115
Offshore Africa (2) 55 76 56 202 206
PRT expense (recovery) -
North Sea 5 (15) 31 (56) 44
Other taxes 4 8 5 22 16
----------------------------------------------------------------------------
Current income tax expense 202 247 189 735 747
----------------------------------------------------------------------------
Deferred income tax
(recovery) expense (36) 159 (34) 163 -
Deferred PRT recovery -
North Sea (60) (36) (35) (132) (30)
----------------------------------------------------------------------------
Deferred income tax
(recovery) expense (96) 123 (69) 31 (30)
----------------------------------------------------------------------------
106 370 120 766 717
Income tax rate and other
legislative changes - - - (15) (58)
----------------------------------------------------------------------------
$ 106 $ 370 $ 120 $ 751 $ 659
----------------------------------------------------------------------------
Effective income tax rate
on adjusted net earnings
from operations (3) 21.4% 27.2% 25.5% 26.2% 27.8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes North America Exploration and Production,
Midstream, and Oil Sands Mining and Upgrading segments.
(2) Includes current income taxes relating to disposition of
properties.
(3) Excludes the impact of current and deferred PRT expense and
other current income tax expense.
The decrease in the effective income tax rate on adjusted net
earnings in the fourth quarter of 2013 from the third quarter of
2013 included the impact of deferred income tax recoveries
recognized in the Company's North Sea operations.
The Company files income tax returns in the various
jurisdictions in which it operates. These tax returns are subject
to periodic examinations in the normal course by the applicable tax
authorities. The tax returns as prepared may include filing
positions that could be subject to differing interpretations of
applicable tax laws and regulations, which may take several years
to resolve. The Company does not believe the ultimate resolution of
these matters will have a material impact upon the Company's
results of operations, financial position or liquidity.
During the second quarter of 2013, the Government of British
Columbia substantively enacted legislation to increase its
provincial corporate income tax rate effective April 1, 2013. As a
result of the income tax rate change, the Company's deferred income
tax liability was increased by $15 million.
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.
For 2014, based on budgeted prices and the current availability
of tax pools, the Company expects to incur current income tax
expense of $675 million to $775 million in Canada and recoveries of
$40 million to $60 million in North Sea and Offshore Africa.
NET CAPITAL EXPENDITURES (1)
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Exploration and Evaluation
Net expenditures
(proceeds) (2) (3) $ 7 $ (238) $ 10 $ (144) $ 309
----------------------------------------------------------------------------
Property, Plant and
Equipment
Net property acquisitions
(2) 61 174 76 246 144
Well drilling, completion
and equipping 600 566 566 2,140 1,902
Production and related
facilities 444 431 495 1,878 1,978
Capitalized interest and
other (4) 34 29 23 120 111
----------------------------------------------------------------------------
Net expenditures 1,139 1,200 1,160 4,384 4,135
----------------------------------------------------------------------------
Total Exploration and
Production 1,146 962 1,170 4,240 4,444
----------------------------------------------------------------------------
Oil Sands Mining and
Upgrading
Horizon Phases 2/3
construction costs 597 550 423 2,057 1,315
Sustaining capital 28 41 94 278 223
Turnaround costs 2 1 5 100 21
Capitalized interest and
other (4) 56 41 19 157 51
----------------------------------------------------------------------------
Total Oil Sands Mining and
Upgrading 683 633 541 2,592 1,610
----------------------------------------------------------------------------
Midstream 185 3 4 197 14
Abandonments (5) 71 44 41 207 204
Head office 6 13 11 38 36
----------------------------------------------------------------------------
Total net capital
expenditures $ 2,091 $ 1,655 $ 1,767 $ 7,274 $ 6,308
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America (2) $ 1,001 $ 1,106 $ 1,086 $ 4,026 $ 4,126
North Sea 95 92 55 334 254
Offshore Africa (3) 50 (236) 29 (120) 64
Oil Sands Mining and
Upgrading 683 633 541 2,592 1,610
Midstream 185 3 4 197 14
Abandonments (5) 71 44 41 207 204
Head office 6 13 11 38 36
----------------------------------------------------------------------------
Total $ 2,091 $ 1,655 $ 1,767 $ 7,274 $ 6,308
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net capital expenditures exclude adjustments related to
differences between carrying amounts and tax values, and other fair
value adjustments.
(2) Includes Business Combinations.
(3) Includes proceeds from the Company's disposition of a 50%
interest in its exploration right in South Africa.
(4) Capitalized interest and other includes expenditures related
to land acquisition and retention, seismic, and other
adjustments.
(5) 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, 2013
were $7,274 million compared with $6,308 million for the year ended
December 31, 2012. Net capital expenditures for the fourth quarter
of 2013 were $2,091 million compared with $1,767 million for the
fourth quarter of 2012 and $1,655 million for the third quarter of
2013.
The increase in capital expenditures for the year ended December
31, 2013 from the year ended December 31, 2012 was primarily due to
the ramp up of Horizon Phase 2/3 site construction activity, the
Horizon turnaround completed in the second quarter of 2013,
increased well drilling and completions spending, Midstream
pipeline construction activity, and the acquisition of Barrick
Energy Inc. in the third quarter of 2013, partially offset by the
disposition of a 50% working interest in Block 11B/12B in South
Africa and the costs associated with the construction of the Kirby
South Project. The increase in capital expenditures for the fourth
quarter of 2013 from the comparable period in 2012 was primarily
due to increases in Horizon Phase 2/3 site construction activity
and Midstream pipeline construction activity. The increase in
capital expenditures for the fourth quarter of 2013 from the third
quarter of 2013 was primarily due to Midstream pipeline
construction activity in the fourth quarter, together with the net
impact of the disposition of a 50% working interest in Block
11B/12B in South Africa and the acquisition of Barrick Energy Inc.
during the third quarter.
During the third quarter of 2013, the Company disposed of a 50%
interest in its exploration right in South Africa, for net cash
consideration of US$255 million, including a recovery of US$14
million of past incurred costs, resulting in an after-tax gain on
sale of exploration and evaluation property of $166 million. In the
event that a commercial crude oil or natural gas discovery occurs
on this exploration right, resulting in the exploration right being
converted into a production right, an additional cash payment would
be due to the Company at such time, amounting to US$450 million for
a commercial crude oil discovery and US$120 million for a
commercial natural gas discovery.
Subsequent to December 31, 2013, the Company entered into an
agreement to acquire certain producing Canadian crude oil and
natural gas properties, together with undeveloped land, for total
cash consideration of approximately $3,125 million, based on an
effective date of January 1, 2014, with a targeted closing date of
April 1, 2014. In connection with the agreement, the Company
negotiated an additional $1,000 million unsecured bank credit
facility with a two-year maturity and with terms similar to the
Company's current syndicated credit facilities, which is available
upon closing. It is the Company's intention to finance the
transaction utilizing cash flow from operations generated in excess
of capital expenditures and available bank credit facilities,
including the new unsecured bank credit facility, while maintaining
the ongoing dividend program.
Drilling Activity (number of wells)
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Net successful natural gas
wells 11 10 3 44 35
Net successful crude oil
wells (1) 324 334 294 1,117 1,203
Dry wells 13 7 19 30 33
Stratigraphic test /
service wells 54 9 116 384 727
----------------------------------------------------------------------------
Total 402 360 432 1,575 1,998
Success rate (excluding
stratigraphic test /
service wells) 96% 98% 94% 97% 97%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes bitumen wells.
North America
North America, excluding Oil Sands Mining and Upgrading,
accounted for approximately 59% of the total capital expenditures
for the year ended December 31, 2013 compared with approximately
69% for the year ended December 31, 2012.
During the fourth quarter of 2013, the Company targeted 11 net
natural gas wells, including 5 wells in Northeast British Columbia,
5 wells in Northwest Alberta and 1 well in Northern Plains. The
Company also targeted 337 net crude oil wells. The majority of
these wells were concentrated in the Company's Northern Plains
region where 259 primary heavy crude oil wells, 12 Pelican Lake
heavy crude oil wells, 38 bitumen (thermal oil) wells and 1 light
oil well were drilled. Another 27 wells targeting light crude oil
were drilled outside the Northern Plains region.
Overall Primrose thermal production for the fourth quarter of
2013 averaged approximately 77,000 bbl/d compared with
approximately 121,000 bbl/d for the fourth quarter of 2012 and
approximately 109,000 bbl/d for the third quarter of 2013.
Production volumes were in line with expectations due to the cyclic
nature of thermal production at Primrose.
In the second quarter of 2013, the Company discovered bitumen
emulsion at surface in areas of the Primrose field. The Company's
view is that the cause of the occurrence is mechanical in nature
and is working collaboratively with the regulators in the causation
review and remediation plans. The Company's near term steaming plan
at the Primrose field has been modified, with steaming being
restricted in certain areas until the causation review with the
regulators is complete.
The next planned phase of the Company's in situ Oil Sands assets
expansion is the Kirby South Project. Site construction is complete
and first steam injection was achieved in September 2013. At
December 31, 2013, steam was being circulated through 6 pads with
well response as expected. Subsequent to December 31, 2013, 15 well
pairs have been fully converted to the production stage.
Development of the tertiary recovery conversion projects at
Pelican Lake continued and 12 horizontal wells were drilled during
the fourth quarter of 2013. Pelican Lake production averaged
approximately 46,000 bbl/d for the fourth quarter of 2013 compared
with 36,000 bbl/d for the fourth quarter of 2012 and 45,500 bbl/d
for the third quarter of 2013.
In order to expand its pipeline infrastructure the Company has
participated in the expansion of the Cold Lake pipeline with
construction anticipated to be completed by 2016.
For the first quarter of 2014, the Company's overall planned
drilling activity in North America is expected to be 248 net crude
oil wells, 8 net bitumen wells and 22 net natural gas wells,
excluding stratigraphic and service wells.
Oil Sands Mining and Upgrading
Phase 2/3 expansion activity in the fourth quarter of 2013 was
focused on field construction of the gas recovery unit, sulphur
recovery unit, butane treatment unit, coker expansion, tank farms,
cooling water tower, tailings, hydrotransport, froth treatment and
extraction trains 3 and 4, along with engineering related to the
froth treatment plants, extraction retrofit of trains 1 and 2,
hydrogen unit, hydrotreater unit, vacuum distillation unit and
distillation recovery unit.
North Sea
In September 2012, the UK government announced the
implementation of the Brownfield Allowance, which allows for an
agreed allowance for certain pre-approved qualifying field
developments. This allowance partially mitigates the impact of
previous supplementary income tax increases. During 2013, the
Company received Brownfield Allowance approvals for the Tiffany and
Ninian fields. At the Tiffany field, during the first quarter, the
Company completed 1 injection well conversion and drilled 1
production well with production of approximately 1,500 bbl/d,
exceeding original forecasted volumes. The Company also commenced
drilling in the Ninian field in the fourth quarter of 2013.
The decommissioning activities at the Murchison platform
commenced in the fourth quarter of 2013 and the Company estimates
the decommissioning efforts will continue for approximately 5
years. In October 2013, the Company entered into a Decommissioning
Relief Deed ("DRD") with the UK government. The DRD was introduced
in 2013 and is a contractual mechanism whereby the UK government
guarantees its participation in future field abandonments through a
recovery of PRT and corporate income tax.
Offshore Africa
During the fourth quarter of 2013, the Company contracted a
drilling rig for a 6 well drilling program at the Baobab field in
Cote d'Ivoire. This rig is expected to arrive in country no later
than the first quarter of 2015. At the Espoir field, the Company is
seeking a drilling rig and is assessing the opportunity to commence
drilling in the latter half of 2014.
Exploration activities continue to progress in both Côte
d'Ivoire and South Africa. In Côte d'Ivoire, the operator in Block
CI-514 is expected to commence drilling 1 exploratory well in March
2014. In South Africa, the operator is targeting to commence
drilling 1 exploratory well in the third quarter of 2014.
LIQUIDITY AND CAPITAL RESOURCES
------------------------------------
Dec 31 Sep 30 Dec 31
($ millions, except ratios) 2013 2013 2012
----------------------------------------------------------------------------
Working capital deficit (1) $ 1,574 $ 969 $ 1,264
Long-term debt (2) (3) $ 9,661 $ 9,393 $ 8,736
Share capital $ 3,854 $ 3,765 $ 3,709
Retained earnings 21,876 21,720 20,516
Accumulated other comprehensive income 42 67 58
----------------------------------------------------------------------------
Shareholders' equity $ 25,772 $ 25,552 $ 24,283
Debt to book capitalization (3) (4) 27% 27% 26%
Debt to market capitalization (3) (5) 20% 21% 22%
After-tax return on average common
shareholders' equity (6) 9% 9% 8%
After-tax return on average capital
employed (3) (7) 7% 7% 7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated as current assets less current liabilities,
excluding the current portion of long-term debt.
(2) Includes the current portion of long-term debt.
(3) Long-term debt is stated at its carrying value, net of fair
value adjustments, original issue discounts and transaction
costs.
(4) Calculated as current and long-term debt; divided by the
book value of common shareholders' equity plus current and
long-term debt.
(5) Calculated as current and long-term debt; divided by the
market value of common shareholders' equity plus current and
long-term debt.
(6) Calculated as net earnings for the twelve month trailing
period; as a percentage of average common shareholders' equity for
the period.
(7) Calculated as net earnings plus after-tax interest and other
financing expense for the twelve month trailing period; as a
percentage of average capital employed for the period.
At December 31, 2013, the Company's capital resources consisted
primarily of cash flow from operations, available bank credit
facilities and access to debt capital markets. Cash flow from
operations and the Company's ability to renew existing bank credit
facilities and raise new debt is dependent on factors discussed in
the "Risks and Uncertainties" section of the Company's annual
MD&A for the year ended December 31, 2012. In addition, the
Company's ability to renew existing bank credit facilities and
raise new debt is also dependent upon maintaining an investment
grade debt rating and the condition of capital and credit markets.
The Company continues to believe that its internally generated cash
flow from operations supported by the implementation of its ongoing
hedge policy, the flexibility of its capital expenditure programs
supported by its multi-year financial plans, its existing bank
credit facilities, and its ability to raise new debt on
commercially acceptable terms will provide sufficient liquidity to
sustain its operations in the short, medium and long term and
support its growth strategy.
The Company established a US commercial paper program in the
first quarter of 2013. Borrowings of up to a maximum US$1,500
million are authorized. The Company reserves capacity under its
bank credit facilities for amounts outstanding under this
program.
At December 31, 2013, the Company had in place bank credit
facilities of $4,801 million, of which approximately $2,937
million, net of commercial paper issuances of $532 million, was
available.
At December 31, 2013, the Company has maturities of long-term
debt aggregating $912 million over the next 12 months (US$500
million due November 2014, US$350 million due December 2014). It is
the Company's intention to retire this indebtedness utilizing cash
flow from operations generated in excess of capital expenditures
and available bank credit facilities as necessary, while
maintaining the ongoing dividend program. On a pro forma basis,
reflecting the retirement of this indebtedness, the available
credit under its bank credit facilities at December 31, 2013 would
amount to $2,025 million.
During the first quarter of 2013, the Company repaid $400
million of 4.50% medium-term notes and US$400 million of 5.15%
notes. During the second quarter of 2013, the $3,000 million
revolving syndicated credit facility was extended to June 2017.
Additionally, the Company issued $500 million of 2.89% medium-term
notes due August 2020. Proceeds from the securities issued were
used to repay bank indebtedness and for general corporate
purposes.
During the fourth quarter of 2013, the Company filed base shelf
prospectuses that allow for the issue of up to $3,000 million of
medium-term notes in Canada and US$3,000 million of debt securities
in the United States until December 2015. If issued, these
securities will bear interest as determined at the date of
issuance.
Long-term debt was $9,661 million at December 31, 2013,
resulting in a debt to book capitalization ratio of 27% (September
30, 2013 - 27%; December 31, 2012 - 26%). This ratio is within the
25% to 45% internal range utilized by management. This range may be
exceeded in periods when a combination of capital projects,
acquisitions, or lower commodity prices occurs. The Company may be
below the low end of the targeted range when cash flow from
operations is greater than current investment activities. The
Company remains committed to maintaining a strong balance sheet,
adequate available liquidity and a flexible capital structure. The
Company has hedged a portion of its production for 2014 and 2015 at
prices that protect investment returns to ensure ongoing balance
sheet strength and the completion of its capital expenditure
programs. Further details related to the Company's long-term debt
at December 31, 2013 are discussed in note 7 to the Company's
unaudited interim consolidated financial statements.
The Company's commodity hedge policy reduces the risk of
volatility in commodity prices and supports the Company's cash flow
for its capital expenditure programs. This policy currently allows
for the hedging of up to 60% of the near 12 months budgeted
production and up to 40% of the following 13 to 24 months estimated
production. For the purpose of this policy, the purchase of put
options is in addition to the above parameters. As at March 5,
2014, an average of approximately 272,000 bbl/d of currently
forecasted 2014 crude oil volumes and approximately 8,000 bbl/d of
currently forecasted 2015 crude oil volumes were hedged using price
collars and physical crude oil sales contracts with fixed WCS
differentials. An additional 500,000 MMBtu/d of natural gas volumes
were hedged for April 2014 to October 2014 using AECO basis swaps.
Further details related to the Company's commodity derivative
financial instruments outstanding at December 31, 2013 are
discussed in note 14 to the Company's unaudited interim
consolidated financial statements.
Share Capital
As at December 31, 2013, there were 1,087,322,000 common shares
outstanding (December 31, 2012 - 1,092,072,000 common shares) and
72,741,000 stock options outstanding. As at March 4, 2014, the
Company had 1,090,824,000 common shares outstanding and 69,845,000
stock options outstanding.
On March 5, 2014, the Company's Board of Directors approved an
increase in the annual dividend to $0.90 per common share (previous
annual dividend rate of $0.80 per common share), beginning with the
quarterly dividend payable on April 1, 2014 at $0.225 per common
share. This represents a 13% increase from the previous quarterly
dividend, reflecting the stability of the Company's cash flow and
providing a return to shareholders. The dividend policy undergoes
periodic review by the Board of Directors and is subject to
change.
In April 2013, the Company announced a Normal Course Issuer Bid
to purchase through the facilities of the Toronto Stock Exchange
("TSX") and the New York Stock Exchange ("NYSE"), during the twelve
month period commencing April 2013 and ending April 2014, up to
54,635,116 common shares. The Company's Normal Course Issuer Bid
announced in 2012 expired April 2013.
For the year ended December 31, 2013, the Company purchased
10,164,800 common shares at a weighted average price of $31.46 per
common share, for a total cost of $320 million. Retained earnings
were reduced by $285 million, representing the excess of the
purchase price of common shares over their average carrying value.
Subsequent to December 31, 2013, the Company purchased 1,475,000
common shares at a weighted average price of $35.85 per common
share for a total cost of $53 million.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. The following table summarizes the Company's
commitments as at December 31, 2013:
($ millions) 2014 2015 2016 2017 2018 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 298 $ 293 $ 225 $ 208 $ 176 $ 1,324
Offshore equipment
operating leases and
offshore drilling $ 147 $ 238 $ 81 $ 61 $ 54 $ 17
Long-term debt (1) $ 1,436 $ 400 $ 931 $ 1,750 $ 426 $ 4,776
Interest and other
financing expense (2) $ 441 $ 405 $ 387 $ 323 $ 270 $ 3,803
Office leases $ 35 $ 41 $ 42 $ 45 $ 47 $ 321
Other $ 309 $ 172 $ 71 $ 1 $ 1 $ 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does
not reflect fair value adjustments, original issue discounts or
transaction costs.
(2) Interest and other financing expense amounts represent the
scheduled fixed rate and variable rate cash interest payments
related to long-term debt. Interest on variable rate long-term debt
was estimated based upon prevailing interest rates and foreign
exchange rates as at December 31, 2013.
In addition to the commitments disclosed above, the Company has
entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These
contracts can be cancelled by the Company upon notice without
penalty, subject to the costs incurred up to and in respect of the
cancellation.
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is a defendant and plaintiff in a number of legal
actions arising in the normal course of business. In addition, the
Company is subject to certain contractor construction claims. The
Company believes that any liabilities that might arise pertaining
to any such matters would not have a material effect on its
consolidated financial position.
CHANGES IN ACCOUNTING POLICIES
For the impact of new accounting standards, refer to the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2012.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements requires the Company to
make estimates, assumptions and judgments in the application of
IFRS that have a significant impact on the financial results of the
Company. Actual results could differ from estimated amounts, and
those differences may be material. A comprehensive discussion of
the Company's significant critical accounting estimates is
contained in the MD&A and the audited consolidated financial
statements for the year ended December 31, 2012.
CONSOLIDATED BALANCE SHEETS
------------------------
As at Dec 31 Dec 31
(millions of Canadian dollars, unaudited) Note 2013 2012
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 16 $ 37
Accounts receivable 1,427 1,197
Inventory 632 554
Prepaids and other 141 126
----------------------------------------------------------------------------
2,216 1,914
Exploration and evaluation assets 4 2,609 2,611
Property, plant and equipment 5 46,487 44,028
Other long-term assets 6 442 427
----------------------------------------------------------------------------
$ 51,754 $ 48,980
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 637 $ 465
Accrued liabilities 2,519 2,273
Current income taxes 359 285
Current portion of long-term debt 7 1,444 798
Current portion of other long-term
liabilities 8 275 155
----------------------------------------------------------------------------
5,234 3,976
Long-term debt 7 8,217 7,938
Other long-term liabilities 8 4,348 4,609
Deferred income taxes 8,183 8,174
----------------------------------------------------------------------------
25,982 24,697
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital 10 3,854 3,709
Retained earnings 21,876 20,516
Accumulated other comprehensive income 11 42 58
----------------------------------------------------------------------------
25,772 24,283
----------------------------------------------------------------------------
$ 51,754 $ 48,980
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments and contingencies (note 15).
Approved by the Board of Directors on March 5, 2014
CONSOLIDATED STATEMENTS OF EARNINGS
Three Months Ended Year Ended
----------------------------------------
(millions of Canadian dollars,
except per common share Dec 31 Dec 31 Dec 31 Dec 31
amounts, unaudited) Note 2013 2012 2013 2012
----------------------------------------------------------------------------
Product sales $ 4,330 $ 4,059 $ 17,945 $ 16,195
Less: royalties (383) (359) (1,800) (1,606)
----------------------------------------------------------------------------
Revenue 3,947 3,700 16,145 14,589
----------------------------------------------------------------------------
Expenses
Production 1,198 1,072 4,559 4,249
Transportation and blending 645 738 2,938 2,752
Depletion, depreciation and
amortization 5 1,272 1,213 4,844 4,328
Administration 93 64 335 270
Share-based compensation 8 65 (41) 135 (214)
Asset retirement obligation
accretion 8 46 38 171 151
Interest and other financing
expense 60 83 279 364
Risk management activities 14 (66) - (77) 120
Foreign exchange loss (gain) 114 58 210 (49)
Gain on corporate
acquisition/disposition of
properties 4,5 - - (289) -
Equity loss from joint venture 6 1 3 4 9
----------------------------------------------------------------------------
3,428 3,228 13,109 11,980
----------------------------------------------------------------------------
Earnings before taxes 519 472 3,036 2,609
Current income tax expense 9 202 189 735 747
Deferred income tax (recovery)
expense 9 (96) (69) 31 (30)
----------------------------------------------------------------------------
Net earnings $ 413 $ 352 $ 2,270 $ 1,892
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common share
Basic 13 $ 0.38 $ 0.32 $ 2.08 $ 1.72
Diluted 13 $ 0.38 $ 0.32 $ 2.08 $ 1.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Year Ended
----------------------------------------
(millions of Canadian dollars, Dec 31 Dec 31 Dec 31 Dec 31
unaudited) 2013 2012 2013 2012
----------------------------------------------------------------------------
Net earnings $ 413 $ 352 $ 2,270 $ 1,892
----------------------------------------------------------------------------
Items that may be reclassified
subsequently to net earnings
Net change in derivative financial
instruments designated as cash
flow hedges
Unrealized (loss) income during
the period, net of taxes of $3
million (2012 - $2 million) -
three months ended;$nil (2012 -
$4 million) - year ended (25) 17 (4) 31
Reclassification to net
earnings, net of taxes of $nil
(2012 - $nil) - three months
ended;$nil (2012 - $nil) - year
ended - (3) (1) (7)
----------------------------------------------------------------------------
(25) 14 (5) 24
Foreign currency translation
adjustment
Translation of net investment - (2) (11) 8
----------------------------------------------------------------------------
Other comprehensive (loss) income,
net of taxes (25) 12 (16) 32
----------------------------------------------------------------------------
Comprehensive income $ 388 $ 364 $ 2,254 $ 1,924
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
Year Ended
------------------------
Dec 31 Dec 31
(millions of Canadian dollars, unaudited) Note 2013 2012
----------------------------------------------------------------------------
Share capital 10
Balance - beginning of year $ 3,709 $ 3,507
Issued upon exercise of stock options 130 194
Previously recognized liability on stock
options exercised for common shares 50 45
Purchase of common shares under Normal Course
Issuer Bid (35) (37)
----------------------------------------------------------------------------
Balance - end of year 3,854 3,709
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of year 20,516 19,365
Net earnings 2,270 1,892
Purchase of common shares under Normal Course
Issuer Bid 10 (285) (281)
Dividends on common shares 10 (625) (460)
----------------------------------------------------------------------------
Balance - end of year 21,876 20,516
----------------------------------------------------------------------------
Accumulated other comprehensive income 11
Balance - beginning of year 58 26
Other comprehensive (loss) income, net of
taxes (16) 32
----------------------------------------------------------------------------
Balance - end of year 42 58
----------------------------------------------------------------------------
Shareholders' equity $ 25,772 $ 24,283
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended Year Ended
----------------------------------------
(millions of Canadian dollars, Dec 31 Dec 31 Dec 31 Dec 31
unaudited) Note 2013 2012 2013 2012
----------------------------------------------------------------------------
Operating activities
Net earnings $ 413 $ 352 $ 2,270 $ 1,892
Non-cash items
Depletion, depreciation and
amortization 1,272 1,213 4,844 4,328
Share-based compensation 65 (41) 135 (214)
Asset retirement obligation
accretion 46 38 171 151
Unrealized risk management
(gain) loss (30) 8 39 (42)
Unrealized foreign exchange
loss 111 254 226 129
Realized foreign exchange
gain on repayment of US
dollar debt securities - (210) (12) (210)
Equity loss from joint
venture 1 3 4 9
Deferred income tax
(recovery) expense (96) (69) 31 (30)
Gain on corporate
acquisition/disposition of
properties - - (289) -
Current income tax on
disposition of properties - - 58 -
Other (92) (94) (19) (47)
Abandonment expenditures (71) (41) (207) (204)
Net change in non-cash working
capital 563 202 (33) 447
----------------------------------------------------------------------------
2,182 1,615 7,218 6,209
----------------------------------------------------------------------------
Financing activities
Issue of bank credit
facilities and commercial
paper, net 52 592 803 172
Issue of medium-term notes,
net 7 - - 98 498
Repayment of US dollar debt
securities - (344) (398) (344)
Issue of common shares on
exercise of stock options 65 30 130 194
Purchase of common shares
under Normal Course Issuer
Bid (46) (118) (320) (318)
Dividends on common shares (136) (115) (523) (444)
Net change in non-cash working
capital (6) (8) (23) (37)
----------------------------------------------------------------------------
(71) 37 (233) (279)
----------------------------------------------------------------------------
Investing activities
Net (expenditures) proceeds on
exploration and evaluation
assets (7) (10) 144 (309)
Net expenditures on property,
plant and equipment (2,013) (1,716) (7,211) (5,795)
Current income tax on
disposition of properties - - (58) -
Investment in other long-term
assets - - - 2
Net change in non-cash working
capital (93) 90 119 175
----------------------------------------------------------------------------
(2,113) (1,636) (7,006) (5,927)
----------------------------------------------------------------------------
(Decrease) increase in cash
and cash equivalents (2) 16 (21) 3
Cash and cash equivalents -
beginning of period 18 21 37 34
----------------------------------------------------------------------------
Cash and cash equivalents -
end of period $ 16 $ 37 $ 16 $ 37
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 95 $ 104 $ 460 $ 464
Income taxes paid $ 43 $ 105 $ 357 $ 639
----------------------------------------------------------------------------
----------------------------------------------------------------------------
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
(tabular amounts in millions of Canadian dollars, unless
otherwise stated, unaudited)
1. ACCOUNTING POLICIES
Canadian Natural Resources Limited (the "Company") is a senior
independent crude oil and natural gas exploration, development and
production company. The Company's exploration and production
operations are focused in North America, largely in Western Canada;
the United Kingdom ("UK") portion of the North Sea; and Cote
d'Ivoire, Gabon, and South Africa in Offshore Africa.
The Horizon Oil Sands Mining and Upgrading segment ("Horizon")
produces synthetic crude oil through bitumen mining and upgrading
operations.
Within Western Canada, the Company maintains certain midstream
activities that include pipeline operations, an electricity
co-generation system and an investment in the North West Redwater
Partnership ("Redwater Partnership"), a general partnership formed
in the Province of Alberta.
The Company was incorporated in Alberta, Canada. The address of
its registered office is 2500, 855-2 Street S.W., Calgary, Alberta,
Canada.
These interim consolidated financial statements and the related
notes have been prepared in accordance with International Financial
Reporting Standards ("IFRS") as issued by the International
Accounting Standards Board ("IASB"), applicable to the preparation
of interim financial statements, including International Accounting
Standard ("IAS") 34, "Interim Financial Reporting", following the
same accounting policies as the audited consolidated financial
statements of the Company as at December 31, 2012, except as
discussed in note 2. These interim consolidated financial
statements contain disclosures that are supplemental to the
Company's annual audited consolidated financial statements. Certain
disclosures that are normally required to be included in the notes
to the annual audited consolidated financial statements have been
condensed. These interim consolidated financial statements should
be read in conjunction with the Company's audited consolidated
financial statements and notes thereto for the year ended December
31, 2012.
2. CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2013, the Company adopted the following new
accounting standards issued by the IASB:
a) - IFRS 10 "Consolidated Financial Statements" replaced IAS 27
"Consolidated and Separate Financial Statements" (IAS 27 still
contains guidance for Separate Financial Statements) and Standing
Interpretations Committee ("SIC") 12 "Consolidation - Special
Purpose Entities". IFRS 10 establishes the principles for the
presentation and preparation of consolidated financial statements.
The standard defines the principle of control and establishes
control as the basis for consolidation, as well as providing
guidance on applying the control principle to determine whether an
investor controls an investee.
- IFRS 11 "Joint Arrangements" replaced IAS 31 "Interests in
Joint Ventures" and SIC 13 "Jointly Controlled Entities -
Non-Monetary Contributions by Venturers". The new standard defines
two types of joint arrangements, joint operations and joint
ventures. In a joint operation, the parties with joint control have
rights to the assets and obligations for the liabilities of the
joint arrangement and are required to recognize their proportionate
interest in the assets, liabilities, revenues and expenses of the
joint arrangement. In a joint venture, the parties have an interest
in the net assets of the arrangement and are required to apply the
equity method of accounting.
- IFRS 12 "Disclosure of Interests in Other Entities". The
standard includes disclosure requirements for investments in
subsidiaries, joint arrangements, associates and unconsolidated
structured entities.
- The Company adopted these standards retrospectively. Adoption
of these standards did not have a material impact on the Company's
consolidated financial statements.
b) IFRS 13 "Fair Value Measurement" provides guidance on the
application of fair value where its use is already required or
permitted by other standards within IFRS. The standard includes a
definition of fair value and a single source of fair value
measurement and disclosure requirements for use across all IFRSs
that require or permit the use of fair value. IFRS 13 was adopted
prospectively. As a result of adoption of this standard, the
Company has included its own credit risk in measuring the carrying
amount of a risk management liability with no material impact on
the Company's consolidated financial statements.
c) Amendments to IAS 1 "Presentation of Financial Statements"
require items of other comprehensive income that may be
reclassified to net earnings to be grouped together. The amendments
also require that items in other comprehensive income and net
earnings be presented as either a single statement or two
consecutive statements. Adoption of this amended standard impacted
presentation only.
d) IFRS Interpretation Committee ("IFRIC") 20 "Stripping Costs
in the Production Phase of a Surface Mine" requires overburden
removal costs during the production phase to be capitalized and
depreciated if the Company can demonstrate that probable future
economic benefits will be realized, the costs can be reliably
measured, and the Company can identify the component of the ore
body for which access has been improved. Adoption of this standard
did not have a material impact on the Company's consolidated
financial statements.
3. ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
In November 2013, the IASB issued amendments to IFRS 9
"Financial Instruments" to provide guidance on hedge accounting and
associated disclosures as part of its overall Financial Instruments
project to replace IAS 39 "Financial Instruments - Recognition and
Measurement". The new hedge accounting guidance in IFRS 9 replaces
strict quantitative tests of effectiveness with less restrictive
assessments of how well the hedging instrument accomplishes the
Company's risk management objectives for financial and
non-financial risk exposures. The new guidance also allows entities
to hedge components of non-financial items.
Previous amendments to IFRS 9 replaced the multiple
classification and measurement models for financial assets and
liabilities with a new model that has only two categories:
amortized cost and fair value through profit and loss. Under IFRS
9, fair value changes due to credit risk for liabilities designated
at fair value through profit and loss would generally be recorded
in other comprehensive income.
As part of the November 2013 amendments to IFRS 9, the IASB
removed the January 1, 2015 mandatory effective date, and did not
provide a new mandatory effective date. However, entities may still
choose to apply IFRS 9 immediately.
Effective January 1, 2014, the Company adopted IFRS 9 with no
material impact on the Company's consolidated financial
statements.
4. EXPLORATION AND EVALUATION ASSETS
Oil Sands
Mining and
Exploration and Production Upgrading Total
----------------------------------------------------------------------------
North North Offshore
America Sea Africa
----------------------------------------------------------------------------
Cost
At December 31, 2012 $ 2,564 $ - $ 47 $ - $ 2,611
Additions 90 - 29 - 119
Transfers to property,
plant and equipment (84) - - - (84)
Disposals - - (39) - (39)
Foreign exchange
adjustments - - 2 - 2
----------------------------------------------------------------------------
At December 31, 2013 $ 2,570 $ - $ 39 $ - $ 2,609
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the third quarter of 2013, the Company disposed of a 50%
interest in its exploration right in South Africa, for net cash
consideration of US$255 million, including a recovery of US$14
million of past incurred costs, resulting in a pre-tax gain on sale
of exploration and evaluation property of $224 million ($166
million after-tax). In the event that a commercial crude oil or
natural gas discovery occurs on this exploration right, resulting
in the exploration right being converted into a production right,
an additional cash payment would be due to the Company at such
time, amounting to US$450 million for a commercial crude oil
discovery and US$120 million for a commercial natural gas
discovery.
5. PROPERTY, PLANT AND EQUIPMENT
Oil Sands
Mining
Exploration and and Head
Production Upgrading Midstream Office Total
----------------------------------------------------------------------------
North North Offshore
America Sea Africa
----------------------------------------------------------------------------
Cost
At December
31, 2012 $ 50,324 $4,574 $ 3,045 $ 16,963 $ 312 $ 270 $75,488
Additions 3,630 299 97 2,772 196 38 7,032
Transfers
from E&E
assets 84 - - - - - 84
Disposals/
derecognitions (228) - - (369) - - (597)
Foreign
exchange
adjustments
and other - 327 214 - - - 541
----------------------------------------------------------------------------
At December
31, 2013 $ 53,810 $5,200 $ 3,356 $ 19,366 $ 508 $ 308 $82,548
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and
depreciation
At December
31, 2012 $ 24,991 $2,709 $ 2,273 $ 1,202 $ 103 $ 182 $31,460
Expense 3,551 548 134 582 8 21 4,844
Disposals/
derecognitions (228) - - (369) - - (597)
Foreign
exchange
adjustments
and other 1 210 144 (1) - - 354
----------------------------------------------------------------------------
At December
31, 2013 $ 28,315 $3,467 $ 2,551 $ 1,414 $ 111 $ 203 $36,061
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book
value- at
December
31, 2013 $ 25,495 $1,733 $ 805 $ 17,952 $ 397 $ 105 $46,487
- at
December
31, 2012 $ 25,333 $1,865 $ 772 $ 15,761 $ 209 $ 88 $44,028
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Project costs not subject to depletion and
depreciation 2013 2012
----------------------------------------------------------------------------
Horizon $ 4,051 $ 2,066
Kirby Thermal Oil Sands $ 1,532 $ 1,021
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During 2013, the Company acquired a number of producing crude
oil and natural gas properties in the North American and North Sea
Exploration and Production segments, including properties from the
acquisition of Barrick Energy Inc. effective July 31, 2013, for
total cash consideration of $252 million (year ended December 31,
2012 - $144 million). These transactions were accounted for using
the acquisition method of accounting. In connection with these
acquisitions, the Company assumed associated asset retirement
obligations of $131 million (year ended December 31, 2012 - $12
million) and recognized net deferred tax assets of $75 million
(year ended December 31, 2012 - $nil) related to temporary
differences in the carrying amount of the acquired properties and
their tax bases. Interests in jointly controlled assets were
acquired with full tax basis. No debt obligations were assumed. The
Company recognized after-tax gains of $65 million (year ended
December 31, 2012 - $nil) on these acquisitions.
Subsequent to December 31, 2013, the Company entered into an
agreement to acquire certain producing Canadian crude oil and
natural gas properties, together with undeveloped land, for total
cash consideration of approximately $3,125 million, based on an
effective date of January 1, 2014, with a targeted closing date of
April 1, 2014. In connection with the agreement, the Company
negotiated an additional $1,000 million unsecured bank credit
facility with a two-year maturity and with terms similar to the
Company's current syndicated credit facilities, which is available
upon closing.
The Company capitalizes construction period interest for
qualifying assets based on costs incurred and the Company's cost of
borrowing. Interest capitalization to a qualifying asset ceases
once the asset is substantially available for its intended use.
During 2013, pre-tax interest of $175 million (December 31, 2012 -
$98 million) was capitalized to property, plant and equipment using
a capitalization rate of 4.4% (December 31, 2012 - 4.8%).
6. OTHER LONG-TERM ASSETS
------------------------
Dec 31 Dec 31
2013 2012
----------------------------------------------------------------------------
Investment in North West Redwater Partnership $ 306 $ 310
Other 136 117
----------------------------------------------------------------------------
$ 442 $ 427
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other long-term assets include an investment in the 50% owned
Redwater Partnership. Based on Redwater Partnership's voting and
decision-making structure and legal form, the investment is
accounted for as a joint venture using the equity method. Redwater
Partnership has entered into agreements to construct and operate a
50,000 barrel per day bitumen upgrader and refinery (the "Project")
under processing agreements that target to process 12,500 barrels
per day of bitumen feedstock for the Company and 37,500 barrels per
day of bitumen feedstock for the Alberta Petroleum Marketing
Commission ("APMC"), an agent of the Government of Alberta, under a
30 year fee-for-service tolling agreement. During 2012, the Project
received board sanction from Redwater Partnership and its
partners.
As at December 31, 2013, Redwater Partnership had interim
borrowings of $702 million under credit facilities totaling $1,200
million with original maturities no later than December 2017. These
facilities are secured by a floating charge on the assets of
Redwater Partnership with a mandatory repayment required from
future financing proceeds. At maturity, under its processing
agreement, the Company would be obligated to pay its 25% pro rata
share of any shortfall.
In December 2013, Redwater Partnership, the Company and APMC
agreed in principle to amend certain terms of the processing
agreements. In conjunction with these amendments, the Company,
along with APMC, each committed to provide additional funding up to
$350 million to attain Project completion based on the revised
Project cost estimate of approximately $8,500 million. The
additional funding is to be in the form of subordinated debt
bearing interest at prime plus 6%, which is anticipated to form
part of the equity toll. Should final Project costs exceed the
revised cost estimate, the Company and APMC have agreed, subject to
the Company being able to meet certain funding conditions, to fund
any shortfall in available third party commercial lending required
to attain Project completion.
Redwater Partnership has entered into various agreements related
to the engineering, procurement and construction of the Project.
These contracts can be cancelled by Redwater Partnership upon
notice without penalty, subject to the costs incurred up to and in
respect of the cancellation.
Subsequent to December 31, 2013, the credit facility maturity
date was amended to mature on November 28, 2014. At maturity or at
such later date as mutually agreed to by the lenders and Redwater
Partnership, the Company will be obligated to repay its 25% pro
rata share of any amount outstanding under the facility. As at
March 4, 2014, interim borrowings under the facilities were $857
million.
7. LONG-TERM DEBT
------------------------
Dec 31 Dec 31
2013 2012
----------------------------------------------------------------------------
Canadian dollar denominated debt, unsecured
Bank credit facilities $ 1,246 $ 971
Medium-term notes 1,400 1,300
----------------------------------------------------------------------------
2,646 2,271
----------------------------------------------------------------------------
US dollar denominated debt, unsecured
Commercial paper (December 31, 2013 - US$500
million; December 31, 2012 - US$nil) 532 -
US dollar debt securities (December 31, 2013 -
US$6,150 million; December 31, 2012 - US$6,550
million) 6,541 6,517
Less: original issue discount on US dollar debt
securities (1) (18) (20)
----------------------------------------------------------------------------
7,055 6,497
Fair value impact of interest rate swaps on US
dollar debt securities (2) 9 19
----------------------------------------------------------------------------
7,064 6,516
----------------------------------------------------------------------------
Long-term debt before transaction costs 9,710 8,787
Less: transaction costs (1) (3) (49) (51)
----------------------------------------------------------------------------
9,661 8,736
Less: current portion of commercial paper 532 -
current portion of other long-term debt (1) (2) (3) 912 798
----------------------------------------------------------------------------
$ 8,217 $ 7,938
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has included unamortized original issue
discounts and directly attributable transaction costs in the
carrying amount of the
outstanding debt.
(2) The carrying amount of US$350 million of 4.90% notes due
December 2014 was adjusted by $9 million (December 31, 2012 - $19
million) to reflect the fair value impact of hedge accounting.
(3) Transaction costs primarily represent underwriting
commissions charged as a percentage of the related debt offerings,
as well as legal, rating agency and other professional fees.
Bank Credit Facilities and Commercial Paper
As at December 31, 2013, the Company had in place bank credit
facilities of $4,801 million, comprised of:
- a $200 million demand credit facility;
- a $75 million demand credit facility;
- a revolving syndicated credit facility of $1,500 million
maturing June 2016;
- a revolving syndicated credit facility of $3,000 million
maturing June 2017; and
- a GBP 15 million demand credit facility related to the
Company's North Sea operations.
During the second quarter of 2013, the $3,000 million revolving
syndicated credit facility was extended to June 2017. Each of the
$3,000 million and $1,500 million facilities is extendible annually
for one-year periods at the mutual agreement of the Company and the
lenders. If the facilities are not extended, the full amount of the
outstanding principal would be repayable on the maturity date.
Borrowings under these facilities may be made by way of pricing
referenced to Canadian dollar or US dollar bankers' acceptances, or
LIBOR, US base rate or Canadian prime loans.
The Company established a US commercial paper program in the
first quarter of 2013. Borrowings of up to a maximum US$1,500
million are authorized. The Company reserves capacity under its
bank credit facilities for amounts outstanding under this
program.
The Company's weighted average interest rate on bank credit
facilities and commercial paper outstanding as at December 31,
2013, was 1.9% (December 31, 2012 - 2.2%), and on long-term debt
outstanding for the year ended December 31, 2013 was 4.4% (December
31, 2012 - 4.8%).
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $395 million, including a $65
million financial guarantee related to Horizon and $226 million of
letters of credit related to North Sea operations, were outstanding
at December 31, 2013.
Medium-Term Notes
During the first quarter of 2013, the Company repaid $400
million of 4.50% medium-term notes.
During the second quarter of 2013, the Company issued $500
million of 2.89% medium-term notes due August 2020. Proceeds from
the securities issued were used to repay bank indebtedness and for
general corporate purposes.
During the fourth quarter of 2013, the Company filed a base
shelf prospectus that allows for the issue of up to $3,000 million
of medium-term notes in Canada, which expires in December 2015. If
issued, these securities will bear interest as determined at the
date of issuance.
US Dollar Debt Securities
During the first quarter of 2013, the Company repaid US$400
million of 5.15% notes.
During the fourth quarter of 2013, the Company filed a base
shelf prospectus that allows for the issue of up to US$3,000
million of debt securities in the United States, which expires in
December 2015. If issued, these securities will bear interest as
determined at the date of issuance.
8. OTHER LONG-TERM LIABILITIES
------------------------
Dec 31 Dec 31
2013 2012
----------------------------------------------------------------------------
Asset retirement obligations $ 4,162 $ 4,266
Share-based compensation 260 154
Risk management (note 14) 136 257
Other 65 87
----------------------------------------------------------------------------
4,623 4,764
Less: current portion 275 155
----------------------------------------------------------------------------
$ 4,348 $ 4,609
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset Retirement Obligations
The Company's asset retirement obligations are expected to be
settled on an ongoing basis over a period of approximately 60 years
and have been discounted using a weighted average discount rate of
5.0% (December 31, 2012 - 4.3%). A reconciliation of the discounted
asset retirement obligations is as follows:
------------------------
Dec 31 Dec 31
2013 2012
----------------------------------------------------------------------------
Balance - beginning of year $ 4,266 $ 3,577
Liabilities incurred 62 51
Liabilities acquired 131 12
Liabilities settled (207) (204)
Asset retirement obligation accretion 171 151
Revision of estimates 375 384
Change in discount rate (723) 315
Foreign exchange adjustments 87 (20)
----------------------------------------------------------------------------
Balance - end of year $ 4,162 $ 4,266
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Share-Based Compensation
As the Company's Option Plan provides current employees with the
right to elect to receive common shares or a direct 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
2013 2012
----------------------------------------------------------------------------
Balance - beginning of year $ 154 $ 432
Share-based compensation expense (recovery) 135 (214)
Cash payment for stock options surrendered (4) (7)
Transferred to common shares (50) (45)
Capitalized to (recovered from) Oil Sands Mining
and Upgrading 25 (12)
----------------------------------------------------------------------------
Balance - end of year 260 154
Less: current portion 216 129
----------------------------------------------------------------------------
$ 44 $ 25
----------------------------------------------------------------------------
----------------------------------------------------------------------------
9. INCOME TAXES
The provision for income tax is as follows:
Three Months Ended Year Ended
----------------------------------------
Dec 31 Dec 31 Dec 31 Dec 31
2013 2012 2013 2012
----------------------------------------------------------------------------
Current corporate income tax - North
America $ 133 $ 68 $ 544 $ 366
Current corporate income tax - North
Sea 5 29 23 115
Current corporate income tax -
Offshore Africa 55 56 202 206
Current PRT (1) expense (recovery) -
North Sea 5 31 (56) 44
Other taxes 4 5 22 16
----------------------------------------------------------------------------
Current income tax expense 202 189 735 747
----------------------------------------------------------------------------
Deferred corporate income tax
(recovery) expense (36) (34) 163 -
Deferred PRT (1) recovery - North
Sea (60) (35) (132) (30)
----------------------------------------------------------------------------
Deferred income tax (recovery)
expense (96) (69) 31 (30)
----------------------------------------------------------------------------
Income tax expense $ 106 $ 120 $ 766 $ 717
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Petroleum Revenue Tax.
During the second quarter of 2013, the Government of British
Columbia substantively enacted legislation to increase its
provincial corporate income tax rate effective April 1, 2013. As a
result of the income tax rate change, the Company's deferred income
tax liability was increased by $15 million.
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.
10. SHARE CAPITAL
Authorized
Preferred shares issuable in a series.
Unlimited number of common shares without par value.
------------------------------
Year Ended Dec 31, 2013
Number of
shares
Issued common shares (thousands) Amount
----------------------------------------------------------------------------
Balance - beginning of year 1,092,072 $ 3,709
Issued upon exercise of stock options 5,415 130
Previously recognized liability on stock
options exercised for common shares - 50
Purchase of common shares under Normal Course
Issuer Bid (10,165) (35)
----------------------------------------------------------------------------
Balance - end of year 1,087,322 $ 3,854
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dividend Policy
The Company has paid regular quarterly dividends in January,
April, July, and October of each year since 2001. The dividend
policy undergoes periodic review by the Board of Directors and is
subject to change.
On March 5, 2014, the Board of Directors set the regular
quarterly dividend at $0.225 per common share, an increase from the
previous quarterly dividend of $0.20 per common share, which was
announced on November 5, 2013.
Normal Course Issuer Bid
In April 2013, the Company announced a Normal Course Issuer Bid
to purchase through the facilities of the Toronto Stock Exchange
and the New York Stock Exchange, during the twelve month period
commencing April 2013 and ending April 2014, up to 54,635,116
common shares. The Company's Normal Course Issuer Bid announced in
2012 expired April 2013.
For the year ended December 31, 2013, the Company purchased for
cancellation 10,164,800 common shares at a weighted average price
of $31.46 per common share, for a total cost of $320 million.
Retained earnings were reduced by $285 million, representing the
excess of the purchase price of common shares over their average
carrying value. Subsequent to December 31, 2013, the Company
purchased 1,475,000 common shares at a weighted average price of
$35.85 per common share for a total cost of $53 million.
Stock Options
The following table summarizes information relating to stock
options outstanding at December 31, 2013:
------------------------------
Year Ended Dec 31, 2013
Weighted
average
Stock options exercise
(thousands) price
----------------------------------------------------------------------------
Outstanding - beginning of year 73,747 $ 34.13
Granted 17,823 $ 32.51
Surrendered for cash settlement (401) $ 23.83
Exercised for common shares (5,415) $ 24.03
Forfeited (13,013) $ 34.93
----------------------------------------------------------------------------
Outstanding - end of year 72,741 $ 34.36
----------------------------------------------------------------------------
Exercisable - end of year 26,632 $ 35.27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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.
11. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of accumulated other comprehensive income, net of
taxes, were as follows:
--------------------
Dec 31 Dec 31
2013 2012
----------------------------------------------------------------------------
Derivative financial instruments designated as cash flow
hedges $ 81 $ 86
Foreign currency translation adjustment (39) (28)
----------------------------------------------------------------------------
$ 42 $ 58
----------------------------------------------------------------------------
----------------------------------------------------------------------------
12. 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, 2013, the ratio was within the target range at
27%.
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
2013 2012
----------------------------------------------------------------------------
Long-term debt (1) $ 9,661 $ 8,736
Total shareholders' equity $ 25,772 $ 24,283
Debt to book capitalization 27% 26%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
13. NET EARNINGS PER COMMON SHARE
Three Months Ended Year Ended
------------------------------------------------
Dec 31 Dec 31 Dec 31 Dec 31
2013 2012 2013 2012
----------------------------------------------------------------------------
Weighted average common
shares outstanding - basic
(thousands of shares) 1,086,271 1,093,925 1,088,682 1,097,084
Effect of dilutive stock
options (thousands of
shares) 1,739 1,604 1,859 2,435
----------------------------------------------------------------------------
Weighted average common
shares outstanding -
diluted (thousands of
shares) 1,088,010 1,095,529 1,090,541 1,099,519
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 413 $ 352 $ 2,270 $ 1,892
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common
share - basic $ 0.38 $ 0.32 $ 2.08 $ 1.72
- diluted $ 0.38 $ 0.32 $ 2.08 $ 1.72
----------------------------------------------------------------------------
----------------------------------------------------------------------------
14. FINANCIAL INSTRUMENTS
The carrying amounts of the Company's financial instruments by
category were as follows:
----------------------------------------------------------
Dec 31, 2013
----------------------------------------------------------------------------
Fair Financial
Loans and value liabilities
receivables through Derivatives at
at amortized profit used for amortized
Asset (liability) cost or loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 1,427 $ - $ - $ - $ 1,427
Accounts payable - - - (637) (637)
Accrued
liabilities - - - (2,519) (2,519)
Other long-term
liabilities - (39) (97) (56) (192)
Long-term debt (1) - - - (9,661) (9,661)
----------------------------------------------------------------------------
$ 1,427 $ (39) $ (97) $ (12,873) $(11,582)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2012
----------------------------------------------------------------------------
Fair Financial
Loans and value liabilities
receivables through Derivatives at
at amortized profit used amortized
Asset (liability) cost or loss for hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 1,197 $ - $ - $ - $ 1,197
Accounts payable - - - (465) (465)
Accrued
liabilities - - - (2,273) (2,273)
Other long-term
liabilities - 4 (261) (79) (336)
Long-term debt
(1) - - - (8,736) (8,736)
----------------------------------------------------------------------------
$ 1,197 $ 4 $ (261) $ (11,553) $(10,613)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
The carrying amounts of the Company's financial instruments
approximates their fair value, except for fixed rate long-term debt
as noted below. The fair values of the Company's other long-term
liabilities and fixed rate long-term debt are outlined below:
---------------------------------------------
Dec 31, 2013
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability)(1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term liabilities $ (136) $ - $ (136)
Fixed rate long-term debt (2)
(3) (4) (7,883) (8,628) -
----------------------------------------------------------------------------
$ (8,019) $ (8,628) $ (136)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2012
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term liabilities $ (257) $ - $ (257)
Fixed rate long-term debt (2)
(3) (4) (7,765) (9,118) -
----------------------------------------------------------------------------
$ (8,022) $ (9,118) $ (257)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes financial assets and liabilities where the carrying
amount approximates fair value due to the liquid nature of the
asset or liability (cash and cash equivalents, accounts receivable,
accounts payable and accrued liabilities).
(2) The carrying amount of US$350 million of 4.90% notes due
December 2014 was adjusted by $9 million (December 31, 2012 - $19
million) to reflect the fair value impact of hedge accounting.
(3) The fair value of fixed rate long-term debt has been
determined based on quoted market prices.
(4) Includes the current portion of fixed rate long-term
debt.
The following provides a summary of the carrying amounts of
derivative financial instruments held and a reconciliation to the
Company's consolidated balance sheets.
------------------------------
Asset (liability) Dec 31, 2013 Dec 31, 2012
----------------------------------------------------------------------------
Derivatives held for trading
Crude oil price collars $ (33) $ (16)
Foreign currency forward contracts (3) 20
Natural gas AECO basis swaps (1) -
Natural gas AECO put options, net of put
premium financing obligations (2) -
Cash flow hedges
Foreign currency forward contracts (1) -
Cross currency swaps (96) (261)
----------------------------------------------------------------------------
$ (136) $ (257)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Included within:
Current portion of other long-term
liabilities $ (38) $ (4)
Other long-term liabilities (98) (253)
----------------------------------------------------------------------------
$ (136) $ (257)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During 2013, the Company recognized a gain of $4 million
(December 31, 2012 - gain of $1 million) related to ineffectiveness
arising from cash flow hedges.
The estimated fair value of derivative financial instruments in
Level 1 and Level 2 at each measurement date have been determined
based on appropriate internal valuation methodologies and/or third
party indications. Level 2 fair values determined using valuation
models require the use of assumptions concerning the amount and
timing of future cash flows and discount rates. In determining
these assumptions, the Company primarily relied on external,
readily-observable quoted market inputs including crude oil and
natural gas forward benchmark commodity prices and volatility,
Canadian and United States forward interest rate yield curves, and
Canadian and United States foreign exchange rates, discounted to
present value as appropriate. The resulting fair value estimates
may not necessarily be indicative of the amounts that could be
realized or settled in a current market transaction and these
differences may be material.
Risk Management
The Company uses derivative financial instruments to manage its
commodity price, interest rate and foreign currency exposures.
These financial instruments are entered into solely for hedging
purposes and are not used for speculative purposes.
The changes in estimated fair values of derivative financial
instruments included in the risk management liability were
recognized in the financial statements as follows:
------------------------------
Asset (liability) Dec 31, 2013 Dec 31, 2012
----------------------------------------------------------------------------
Balance - beginning of year $ (257) $ (274)
Cost of outstanding put options 9 -
Net change in fair value of outstanding
derivative financial instruments attributable
to:
Risk management activities (39) 42
Foreign exchange 165 (53)
Other comprehensive income (5) 28
----------------------------------------------------------------------------
(127) (257)
Add: put premium financing obligations (1) (9) -
----------------------------------------------------------------------------
Balance - end of year (136) (257)
Less: current portion (38) (4)
----------------------------------------------------------------------------
$ (98) $ (253)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has negotiated payment of put option premiums
with various counterparties at the time of actual settlement of the
respective options. These obligations are reflected in the risk
management liability.
Net (gains) losses from risk management activities were as
follows:
Three Months Ended Year Ended
----------------------------------------
Dec 31 Dec 31 Dec 31 Dec 31
2013 2012 2013 2012
----------------------------------------------------------------------------
Net realized risk management (gain)
loss $ (36) $ (8) $ (116) $ 162
Net unrealized risk management
(gain) loss (30) 8 39 (42)
----------------------------------------------------------------------------
$ (66) $ - $ (77) $ 120
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, 2013,
the Company had the following derivative financial instruments
outstanding to manage its commodity price risk:
Sales contracts
Weighted average
Remaining term Volume price Index
----------------------------------------------------------------------------
Crude oil
Price collars
(1) Jan 2014 - Jun 2014 50,000 bbl/d US$80.00 - US$123.09 Brent
Jan 2014 - Dec 2014 50,000 bbl/d US$75.00 - US$121.57 Brent
Jan 2014 - Dec 2014 50,000 bbl/d US$80.00 - US$120.17 Brent
Jan 2014 - Dec 2014 50,000 bbl/d US$90.00 - US$120.10 Brent
Jan 2015 - Dec 2015 2,000 bbl/d US$80.00 - US$122.55 Brent
Jan 2014 - Jun 2014 50,000 bbl/d US$80.00 - US$107.84 WTI
Jan 2014 - Dec 2014 50,000 bbl/d US$75.00 - US$105.54 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to December 31, 2013, the Company entered into an
additional 50,000 bbl/d of US$80.00 - US$122.09 Brent collars for
the period July 2014 to September 2014 and an additional 6,000
bbl/d of US$80.00 - US$122.52 Brent collars for the period January
2015 to December 2015.
Weighted average
Remaining term Volume price Index
----------------------------------------------------------------------------
Natural gas
AECO basis 500,000
swaps Apr 2014 - Oct 2014 MMBtu/d US$0.50 AECO/NYMEX
AECO put options (1)
Apr 2014 - Oct 2014 470,000 GJ/d $3.10 AECO
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to December 31, 2013, the Company entered into an
additional 280,000 GJ/d of $3.10 AECO put options for the period
April 2014 to October 2014 for a total cost of $6 million.
The cost of outstanding put options and their respective periods
of settlement as at December 31, 2013 are as follows:
Q2 2014 Q3 2014 Q4 2014
----------------------------------------------------------------------------
Cost $4 $4 $1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's outstanding commodity derivative financial
instruments are expected to be settled monthly based on the
applicable index pricing for the respective contract month.
Interest rate risk management
The Company is exposed to interest rate price risk on its fixed
rate long-term debt and to interest rate cash flow risk on its
floating rate long-term debt. The Company periodically enters into
interest rate swap contracts to manage its fixed to floating
interest rate mix on long-term debt. Interest rate swap contracts
require the periodic exchange of payments without the exchange of
the notional principal amounts on which the payments are based. At
December 31, 2013, the Company had no interest rate swap contracts
outstanding.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated long-term
debt, commercial paper and working capital. The Company is also
exposed to foreign currency exchange rate risk on transactions
conducted in other currencies and in the carrying value of its
foreign subsidiaries. The Company periodically enters into cross
currency swap contracts and foreign currency forward contracts to
manage known currency exposure on US dollar denominated long-term
debt, commercial paper and working capital. The cross currency swap
contracts require the periodic exchange of payments with the
exchange at maturity of notional principal amounts on which the
payments are based. At December 31, 2013, the Company had the
following cross currency swap contracts outstanding:
Exchange
rate Interest Interest
Remaining term Amount (US$/C$) rate (US$) rate (C$)
----------------------------------------------------------------------------
Cross currency
Swaps Jan 2014 - Aug 2016 US$250 1.116 6.00% 5.40%
Jan 2014 - May 2017 US$1,100 1.170 5.70% 5.10%
Jan 2014 - Nov 2021 US$500 1.022 3.45% 3.96%
Jan 2014 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All cross currency swap derivative financial instruments
designated as hedges at December 31, 2013, were classified as cash
flow hedges.
In addition to the cross currency swap contracts noted above, at
December 31, 2013, the Company had US$2,237 million of foreign
currency forward contracts outstanding, with terms of approximately
30 days or less, including US$500 million designated as cash flow
hedges.
b) Credit risk
Credit risk is the risk that a party to a financial instrument
will cause a financial loss to the Company by failing to discharge
an obligation.
Counterparty credit risk management
The Company's accounts receivable are mainly with customers in
the crude oil and natural gas industry and are subject to normal
industry credit risks. The Company manages these risks by reviewing
its exposure to individual companies on a regular basis and where
appropriate, ensures that parental guarantees or letters of credit
are in place to minimize the impact in the event of default. At
December 31, 2013, substantially all of the Company's accounts
receivable were due within normal trade terms.
The Company is also exposed to possible losses in the event of
nonperformance by counterparties to derivative financial
instruments; however, the Company manages this credit risk by
entering into agreements with counterparties that are substantially
all investment grade financial institutions and other entities. At
December 31, 2013, the Company had no net risk management assets
with specific counterparties related to derivative financial
instruments (December 31, 2012 - $18 million).
c) Liquidity risk
Liquidity risk is the risk that the Company will encounter
difficulty in meeting obligations associated with financial
liabilities.
Management of liquidity risk requires the Company to maintain
sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating
activities, available credit facilities, commercial paper and
access to debt capital markets, to meet obligations as they become
due. The Company believes it has adequate bank credit facilities to
provide liquidity to manage fluctuations in the timing of the
receipt and/or disbursement of operating cash flows.
The maturity dates for financial liabilities are as follows:
1 to less 2 to less
Less than than than
1 year 2 years 5 years Thereafter
----------------------------------------------------------------------------
Accounts payable $ 637 $ - $ - $ -
Accrued liabilities $ 2,519 $ - $ - $ -
Risk management $ 38 $ 35 $ 44 $ 19
Other long-term liabilities $ 21 $ 35 $ - $ -
Long-term debt (1) $ 1,436 $ 400 $ 3,107 $ 4,776
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does
not reflect fair value adjustments, interest, original issue
discounts or transaction costs.
15. COMMITMENTS AND CONTINGENCIES
The Company has committed to certain payments as follows:
2014 2015 2016 2017 2018 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 298 $ 293 $ 225 $ 208 $ 176 $ 1,324
Offshore equipment
operating leases and
offshore drilling $ 147 $ 238 $ 81 $ 61 $ 54 $ 17
Office leases $ 35 $ 41 $ 42 $ 45 $ 47 $ 321
Other $ 309 $ 172 $ 71 $ 1 $ 1 $ 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In addition to the commitments disclosed above, the Company has
entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These
contracts can be cancelled by the Company upon notice without
penalty, subject to the costs incurred up to and in respect of the
cancellation.
The Company is 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.
16. SEGMENTED INFORMATION
Exploration and Production
North America North Sea
Three Months Three Months
(millions of Canadian Ended Year Ended Ended Year Ended
dollars,unaudited) Dec 31 Dec 31 Dec 31 Dec 31
--------------------------------------------------
2013 2012 2013 2012 2013 2012 2013 2012
----------------------------------------------------------------------------
Segmented product sales 2,833 3,006 12,659 11,607 229 215 805 928
Less: royalties (281) (277)(1,477)(1,268) - - (2) (2)
----------------------------------------------------------------------------
Segmented revenue 2,552 2,729 11,182 10,339 229 215 803 926
----------------------------------------------------------------------------
Segmented expenses
Production 578 557 2,351 2,165 134 100 431 402
Transportation and
blending 647 735 2,939 2,735 2 2 6 10
Depletion, depreciation
and amortization 905 965 3,568 3,413 184 74 552 296
Asset retirement
obligation accretion 23 21 92 85 9 7 35 27
Realized risk management
activities (36) (8) (116) 162 - - - -
Gain on corporate
acquisition/disposition
of properties - - (65) - - - - -
Equity loss from joint
venture - - - - - - - -
----------------------------------------------------------------------------
Total segmented expenses 2,117 2,270 8,769 8,560 329 183 1,024 735
----------------------------------------------------------------------------
Segmented earnings (loss)
before the following 435 459 2,413 1,779 (100) 32 (221) 191
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Share-based compensation
Interest and other
financing expense
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
Three Months Three Months
(millions of Canadian Ended Year Ended Ended Year Ended
dollars,unaudited) Dec 31 Dec 31 Dec 31 Dec 31
--------------------------------------------------
2013 2012 2013 2012 2013 2012 2013 2012
----------------------------------------------------------------------------
Segmented product sales 335 158 824 773 3,397 3,379 14,288 13,308
Less: royalties (52) (53) (137) (199) (333) (330)(1,616)(1,469)
----------------------------------------------------------------------------
Segmented revenue 283 105 687 574 3,064 3,049 12,672 11,839
----------------------------------------------------------------------------
Segmented expenses
Production 91 39 191 163 803 696 2,973 2,730
Transportation and
blending - - 1 1 649 737 2,946 2,746
Depletion, depreciation
and amortization 44 58 134 165 1,133 1,097 4,254 3,874
Asset retirement
obligation accretion 6 2 10 7 38 30 137 119
Realized risk management
activities - - - - (36) (8) (116) 162
Gain on corporate
acquisition/disposition
of properties - - (224) - - - (289) -
Equity loss from joint
venture - - - - - - - -
----------------------------------------------------------------------------
Total segmented expenses 141 99 112 336 2,587 2,552 9,905 9,631
----------------------------------------------------------------------------
Segmented earnings (loss)
before the following 142 6 575 238 477 497 2,767 2,208
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Share-based compensation
Interest and other
financing expense
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
Three Months Three Months
(millions of Canadian Ended Year Ended Ended Year Ended
dollars,unaudited) Dec 31 Dec 31 Dec 31 Dec 31
--------------------------------------------------
2013 2012 2013 2012 2013 2012 2013 2012
----------------------------------------------------------------------------
Segmented product sales 915 675 3,631 2,871 26 26 110 93
Less: royalties (50) (29) (184) (137) - - - -
----------------------------------------------------------------------------
Segmented revenue 865 646 3,447 2,734 26 26 110 93
----------------------------------------------------------------------------
Segmented expenses
Production 389 372 1,567 1,504 8 8 34 29
Transportation and
blending 15 15 63 61 - - - -
Depletion, depreciation
and amortization 137 114 582 447 2 2 8 7
Asset retirement
obligation accretion 8 8 34 32 - - - -
Realized risk management
activities - - - - - - - -
Gain on corporate
acquisition/disposition
of properties - - - - - - - -
Equity loss from joint
venture - - - - 1 3 4 9
----------------------------------------------------------------------------
Total segmented expenses 549 509 2,246 2,044 11 13 46 45
----------------------------------------------------------------------------
Segmented earnings (loss)
before the following 316 137 1,201 690 15 13 64 48
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Share-based compensation
Interest and other
financing expense
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
Three Months Three Months
(millions of Canadian Ended Year Ended Ended Year Ended
dollars,unaudited) Dec 31 Dec 31 Dec 31 Dec 31
--------------------------------------------------
2013 2012 2013 2012 2013 2012 2013 2012
----------------------------------------------------------------------------
Segmented product sales (8) (21) (84) (77) 4,330 4,059 17,945 16,195
Less: royalties - - - - (383) (359)(1,800)(1,606)
----------------------------------------------------------------------------
Segmented revenue (8) (21) (84) (77) 3,947 3,700 16,145 14,589
----------------------------------------------------------------------------
Segmented expenses
Production (2) (4) (15) (14) 1,198 1,072 4,559 4,249
Transportation and
blending (19) (14) (71) (55) 645 738 2,938 2,752
Depletion, depreciation
and amortization - - - - 1,272 1,213 4,844 4,328
Asset retirement
obligation accretion - - - - 46 38 171 151
Realized risk management
activities - - - - (36) (8) (116) 162
Gain on corporate
acquisition/disposition
of properties - - - - - - (289) -
Equity loss from joint
venture - - - - 1 3 4 9
----------------------------------------------------------------------------
Total segmented expenses (21) (18) (86) (69) 3,126 3,056 12,111 11,651
----------------------------------------------------------------------------
Segmented earnings (loss)
before the following 13 (3) 2 (8) 821 644 4,034 2,938
----------------------------------------------------------------------------
Non-segmented expenses
Administration 93 64 335 270
Share-based compensation 65 (41) 135 (214)
Interest and other
financing expense 60 83 279 364
Unrealized risk management
activities (30) 8 39 (42)
Foreign exchange loss
(gain) 114 58 210 (49)
----------------------------------------------------------------------------
Total non-segmented
expenses 302 172 998 329
----------------------------------------------------------------------------
Earnings before taxes 519 472 3,036 2,609
Current income tax expense 202 189 735 747
Deferred income tax
(recovery) expense (96) (69) 31 (30)
----------------------------------------------------------------------------
Net earnings 413 352 2,270 1,892
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital Expenditures (1)
Year Ended
------------------------------------------------
Dec 31, 2013
----------------------------------------------------------------------------
Non-cash
Net and fair value Capitalized
expenditures changes(2) costs
----------------------------------------------------------------------------
Exploration and evaluation
assets
Exploration and Production
North America $ 90 $ (84) $ 6
North Sea - - -
Offshore Africa (3) (10) - (10)
----------------------------------------------------------------------------
$ 80 $ (84) $ (4)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Property, plant and
equipment
Exploration and Production
North America $ 3,936 $ (450) $ 3,486
North Sea 334 (35) 299
Offshore Africa 114 (17) 97
----------------------------------------------------------------------------
4,384 (502) 3,882
Oil Sands Mining and
Upgrading (4) 2,592 (189) 2,403
Midstream 197 (1) 196
Head office 38 - 38
----------------------------------------------------------------------------
$ 7,211 $ (692) $ 6,519
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 (3) 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 (4) 1,610 142 1,752
Midstream 14 - 14
Head office 36 - 36
----------------------------------------------------------------------------
$ 5,795 $ 795 $ 6,590
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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) The above noted figures do not include the impact of a
pre-tax gain on sale of exploration and evaluation assets totaling
$224 million on the Company's disposition of a 50% interest in its
exploration right in South Africa during 2013.
(4) Net expenditures for Oil Sands Mining and Upgrading also
include capitalized interest and share-based compensation.
Segmented Assets
Total Assets
------------------------
Dec 31 Dec 31
2013 2012
----------------------------------------------------------------------------
Exploration and Production
North America $ 29,234 $ 29,012
North Sea 1,964 1,993
Offshore Africa 981 924
Other 25 36
Oil Sands Mining and Upgrading 18,604 16,291
Midstream 841 636
Head office 105 88
----------------------------------------------------------------------------
$ 51,754 $ 48,980
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUPPLEMENTARY INFORMATION
INTEREST COVERAGE RATIOS
The following financial ratios are provided in connection with
the Company's continuous offering of medium-term notes pursuant to
the short form prospectus dated November 2013. These ratios are
based on the Company's interim consolidated financial statements
that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the twelve month period ended
December 31, 2013:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 7.7x
Cash flow from operations (2) 18.8x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 6, 2014. The North American
conference call number is 1-800-565-0813 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 13, 2014. 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 9268845.
WEBCAST
The conference call will also be broadcast live on the internet
and may be accessed through the Canadian Natural website at
www.cnrl.com.
Contacts: Steve W. Laut President Corey B. Bieber Chief
Financial Officer & Senior Vice-President, Finance Douglas A.
Proll Executive Vice-President Canadian Natural Resources Limited
2500, 855 - 2nd Street S.W. Calgary, Alberta, T2P 4J8 (403)
514-7777 (403) 514-7888 (FAX) ir@cnrl.com www.cnrl.com
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