Canadian Natural Resources Limited (TSX:CNQ) (NYSE:CNQ)
Commenting on fourth quarter and year end results, Canadian
Natural's Vice-Chairman, John Langille stated, "Canadian Natural
generated in 2012 over $6.0 billion of annual cash flow from
operations and demonstrated capital discipline throughout the year.
The Company's exhibited long term ability to maintain flexibility
of capital allocation and financial discipline over different
commodity price cycles has helped us weather challenging conditions
and capitalize when opportunities arise. Prudent management of our
balance sheet resulted in year-end debt to book capitalization of
26% and year-end debt to EBITDA of 1.2 times.
As part of the Company's long term goal to return funds to its
shareholders, throughout 2012, the Company purchased for
cancellation under its Normal Course Issuer Bid over eleven million
common shares at an average price of $28.91. For 2013, the Board
has approved a 19% dividend increase to C$0.125 per quarter, C$0.50
per share annualized. This will be the thirteenth consecutive year
that the Company has announced an increased annual dividend
distribution representing a compound annual growth rate of 21% over
the period. In addition, the Company's Board of Directors have
directed Management to continue with an active program, subject to
market conditions, to purchase for cancellation common shares under
the Company's Normal Course Issuer Bid at or above the levels of
shares purchased in financial year 2012. Our share purchase program
and dividend increases, along with the defined resource development
of our diverse asset base, and our debt management and
opportunistic acquisitions demonstrate our balanced approach to our
long standing effective strategy. Canadian Natural is strong and
stable, and well positioned to deliver shareholder value in the
near, mid and long term."
Steve Laut, President of Canadian Natural concluded, "During
2012, the Company made very good progress in our transition to a
longer life, low decline asset base. We continued to balance
development of our large resource base by focusing on high return
assets and our ability to deliver timely results. In 2012 we made
significant progress towards continued execution on the creation of
shareholder value. We achieved 9% overall production growth in 2012
from 2011. At Horizon, substantial improvements have been made in
operating discipline and our enhanced concentration on safe, steady
and reliable operations has led to greater plant reliability. At
Kirby, construction progress has been solid and we are 81% complete
and on budget. We had another solid year of adding new reserves.
Our barrel of oil equivalent reserves on a Company Gross proved
plus probable basis increased by 5% to 7.9 billion barrels,
replacing 246% of our 2012 production.
For 2013 and beyond, we will continue to focus on operating
efficiencies and discipline and will allocate capital to projects
that provide the greatest value and highest returns to our
shareholders. This will allow the Company over time to generate
strong and growing free cash flow."
QUARTERLY AND ANNUAL HIGHLIGHTS
Three Months Ended Year Ended
-------------------------------------------------------
($ Millions, except
per common share Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
amounts) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings $ 352 $ 360 $ 832 $ 1,892 $ 2,643
Per common share -
basic $ 0.32 $ 0.33 $ 0.76 $ 1.72 $ 2.41
- diluted $ 0.32 $ 0.33 $ 0.76 $ 1.72 $ 2.40
Adjusted net earnings
from operations (1) $ 359 $ 353 $ 972 $ 1,618 $ 2,540
Per common share -
basic $ 0.33 $ 0.33 $ 0.89 $ 1.48 $ 2.32
- diluted $ 0.33 $ 0.32 $ 0.88 $ 1.47 $ 2.30
Cash flow from
operations (2) $ 1,548 $ 1,431 $ 2,158 $ 6,013 $ 6,547
Per common share -
basic $ 1.41 $ 1.31 $ 1.97 $ 5.48 $ 5.98
- diluted $ 1.41 $ 1.30 $ 1.96 $ 5.47 $ 5.94
Capital expenditures,
net of dispositions $ 1,767 $ 1,621 $ 1,909 $ 6,308 $ 6,414
Daily production,
before royalties
Natural gas
(MMcf/d) 1,134 1,191 1,280 1,220 1,257
Crude oil and NGLs
(bbl/d) 469,964 469,168 444,286 451,378 389,053
Equivalent
production (BOE/d)
(3) 658,973 667,616 657,599 654,665 598,526
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Adjusted net earnings from operations is a non-GAAP measure
that the Company utilizes to evaluate its performance. The
derivation of this measure is discussed in the Management's
Discussion and Analysis ("MD&A").
(2) Cash flow from operations is a non-GAAP measure that the
Company considers key as it demonstrates the Company's ability to
fund capital reinvestment and debt repayment. The derivation of
this measure is discussed in the MD&A.
(3) A barrel of oil equivalent ("BOE") is derived by converting
six thousand cubic feet ("Mcf") of natural gas to one barrel
("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be
misleading, particularly if used in isolation, since the 6 Mcf:1
bbl ratio is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead. In comparing the value ratio
using current crude oil prices relative to natural gas prices, the
6 Mcf:1 bbl conversion ratio may be misleading as an indication of
value.
Fourth Quarter
- Total crude oil and NGLs production was 469,964 bbl/d for
Q4/12. Q4/12 crude oil production volumes increased 6% from Q4/11
as a result of a strong thermal in situ production cycle and
successful primary heavy and light crude oil drilling programs.
- Total natural gas production for Q4/12 was 1,134 MMcf/d. Q4/12
natural gas production volumes decreased 11% and 5%, as expected,
from Q4/11 and Q3/12 respectively. The decrease in production was
primarily due to expected production declines and shut in
production volumes as a result of the Company's strategic decision
to allocate capital to higher return crude oil projects.
- Canadian Natural generated quarterly cash flow from operations
of $1.55 billion compared with $2.16 billion in Q4/11 and $1.43
billion in Q3/12. The decrease in cash flow from Q4/11 was due to
lower average realized product prices, lower natural gas sales
volumes, and lower synthetic crude oil ("SCO") sales volumes. These
factors were partially offset by higher crude oil sales volumes in
North America. The increase in cash flow from Q3/12 was primarily
related to higher North America crude oil and NGLs sales
volumes.
- Adjusted net earnings from operations for Q4/12 was $359
million, compared to adjusted net earnings of $972 million in Q4/11
and $353 million in Q3/12. Changes in adjusted net earnings reflect
the changes in cash flow from operations.
Annual
- Total overall production for the year averaged 654,665 BOE/d
representing an increase of 9% from 2011. Canadian Natural's
production volume growth was driven by successful light and heavy
crude oil drilling programs and greater reliability of Horizon Oil
Sands ("Horizon") operations.
- Total crude oil and NGLs production for the year averaged
451,378 bbl/d, an increase of 16% from 2011. The Company's
strategic allocation of capital to crude oil projects resulted in a
22% annual increase in primary heavy crude oil production volumes,
a 13% annual increase of North America light crude oil and NGLs
production and a 113% annual increase in Horizon production.
- As expected, total natural gas production for the year
averaged 1,220 MMcf/d, a decrease of 3% from 2011 levels. The
decrease in production was due to expected production declines,
shut in production volumes and a reduced drilling program,
reflecting Canadian Natural's strategic decision to allocate
capital to higher return crude oil projects.
- Cash flow from operations was approximately $6.0 billion in
2012 compared to approximately $6.5 billion in 2011. The decrease
in cash flow was primarily due to lower realized crude oil and NGLs
prices, lower realized natural gas prices and lower realized SCO
prices. These factors were partially offset by higher crude oil and
SCO production volumes in North America.
- Adjusted net earnings from operations in 2012 decreased to
$1.6 billion compared to $2.5 billion in 2011. Changes in adjusted
net earnings reflect the changes in cash flow from operations and
higher depletion, depreciation and amortization ("DD&A")
expense.
- Canadian Natural's crude oil and natural gas reserves were
reviewed and evaluated by independent qualified reserves
evaluators. The following are highlights based on the Company Gross
reserves using forecast prices and costs as at December 31,
2012:
-- Company Gross proved crude oil, SCO, bitumen and NGL reserves
increased 6% to 4.33 billion barrels. Company Gross proved natural
gas reserves decreased 7% to 4.14 Tcf. On a BOE basis total proved
reserves increased 4% to 5.02 billion BOE.
-- Company Gross proved plus probable crude oil, SCO, bitumen
and NGL reserves increased 6% to 6.92 billion barrels. Company
Gross proved plus probable natural gas reserves decreased 5% to
5.79 Tcf. On a BOE basis total proved plus probable reserves
increased 5% to 7.89 billion BOE.
-- Company Gross proved reserve additions, including
acquisitions, were 404 million barrels of crude oil, SCO, bitumen
and NGL and 135 billion cubic feet of natural gas for 426 million
BOE. The total proved reserve replacement ratio was 178%. The total
proved reserve life index is 22.8 years.
-- Company Gross proved plus probable reserve additions,
including acquisitions, were 565 million barrels of crude oil,
bitumen, SCO and NGL and 132 billion cubic feet of natural gas for
587 million BOE. The total proved plus probable reserve replacement
ratio was 246%. The total proved plus probable reserve life index
is 35.8 years.
-- Proved undeveloped crude oil, SCO, bitumen and NGL reserves
accounted for 31% of the corporate total proved reserves and proved
undeveloped natural gas reserves accounted for 4% of the corporate
total proved reserves.
-- Of the reserve additions by the Company in 2012, 95% of
Company Gross proved reserve additions and 96% of Company Gross
proved plus probable reserve additions were crude oil, SCO, bitumen
and NGLs.
- Total net exploration and production reserve replacement
expenditures totaled approximately $4,444 million in 2012,
including acquisitions and excluding Horizon. Horizon project
capital (including capitalized interest, share-based compensation
and other) totaled approximately $1,366 million and sustaining and
turnaround capital totaled approximately $244 million.
Operational and Financial
- North America Exploration and Production crude oil and NGLs
production for the year averaged 326,829 bbl/d representing an
increase of 11% from 2011 levels.
-- Canadian Natural's primary heavy crude oil continued to
provide strong netbacks and the highest return on capital in the
Company's portfolio of diverse and balanced assets. Primary heavy
crude oil operations achieved Q4/12 production volumes of over
130,000 bbl/d, resulting in the eighth consecutive quarter of
record production which contributed to 22% average annual
production growth over 2011. Primary heavy crude oil production
volumes are targeted to increase by a further 13% in 2013.
-- Completion of another successful light crude oil drilling
program of 124 net wells, Enhanced Oil Recovery ("EOR") activities
and acquisitions resulted in 13% annual growth of North America
light crude oil and NGLs production volumes over 2011 levels. North
America light crude oil and NGLs production volumes in 2013 are
targeted to increase by 6%.
-- Pelican Lake reservoir performance throughout 2012 was very
positive. In Q4/12, production averaged approximately 36,400 bbl/d
as volumes at Pelican Lake were restricted due to temporary
produced polymer treatment and facility constraints. In addition,
production volumes from the primary heavy oil area of Woodenhouse
were also restricted as they utilize Pelican Lake processing
facilities. Construction completion of a new battery targeted in
June 2013 will correct the temporary treatment constraints and
enable a step increase in Pelican Lake and Woodenhouse production
volumes through the second half of 2013. Annual production guidance
for Pelican Lake remains unchanged and is targeted to range from
46,000 bbl/d to 50,000 bbl/d.
-- Thermal in situ production ramped up during 2012 as pads
re-entered the production cycle. Q4/12 volumes averaged 121,000
bbl/d, a 19% increase over Q3/12 volumes. 2012 annual thermal
production averaged approximately 99,500 bbl/d and is targeted to
grow by 5% in 2013.
-- In 2012, Canadian Natural acquired an additional 12,630 net
hectares of leases at its Kirby Thermal Oil Sands Project ("Kirby
Project"), which are being incorporated into the Company's robust
portfolio of thermal in situ projects. The Company's thermal
projects are targeted to add 40,000 bbl/d of production every two
to three years that is targeted to ultimately grow to approximately
500,000 bbl/d of capacity, from current production capacity of
130,000 bbl/d. The Company Gross proved plus probable long-life,
low-decline bitumen reserves from thermal in situ oil sands
increased by 23%, to 2,122 million barrels in 2012 and total
Company Gross proved bitumen reserves increased by 9%, to 1,066
million barrels in 2012.
-- Kirby South Phase 1, the Company's first large scale steam
assisted gravity drainage ("SAGD") project, is targeted for first
steam in Q4/13 and is targeted to add 40,000 bbl/d of production in
late 2014. Construction is progressing slightly ahead of schedule
and on budget.
- Horizon SCO production volumes averaged approximately 86,000
bbl/d in 2012. The Company continues its enhanced focus on
operational discipline and safe, steady and reliable operations at
Horizon. Reliability of the Horizon plant continues to steadily
improve and annual SCO production is targeted to range from 100,000
bbl/d to 108,000 bbl/d in 2013, which includes the impact of the
planned May 2013 turnaround.
-- The addition of the third ore preparation plant ("OPP") and
associated hydro-transport unit was integrated into the Company's
mining operations in early 2012. The equipment has substantially
increased the overall reliability at Horizon.
-- In January and February 2013, strong performance from Horizon
resulted in average SCO volumes of approximately 113,000 bbl/d and
107,000 bbl/d, respectively. Q1/13 production guidance is targeted
to range from 105,000 bbl/d to 111,000 bbl/d of SCO.
-- Canadian Natural maintains a flexible schedule for Horizon
expansion construction to ensure capital efficiencies. The staged
expansion to 250,000 bbl/d of SCO production capacity at Horizon
continues to be broken down into smaller more focused projects
which has kept projects currently under construction trending at or
below cost estimates. In 2012, long life, low decline SCO Company
Gross proved reserves increased 6% to 2.26 billion barrels. SCO
Company Gross proved plus probable reserves remained essentially
unchanged at 3.35 billion barrels.
- During Q4/12, the Redwater Partnership 50,000 bbl/d bitumen
refinery (78,000 bbl/d of bitumen blend) was sanctioned by its
owners (50% Canadian Natural). The Company will provide 12,500
bbl/d of bitumen feedstock to the refinery as a toll payer. Work
continues on the Redwater project and completion is targeted for
mid-2016.
- During 2012, Canadian Natural purchased 11,012,700 common
shares for cancellation at a weighted average price of $28.91 per
common share.
- For 2013, the Board has approved a 19% dividend increase to
C$0.125 per quarter, C$0.50 per share annualized. This will be the
thirteenth consecutive year that the Company has announced an
increased annual dividend distribution representing a compound
annual growth rate of 21% over the period.
- In addition, the Company's Board of Directors have directed
Management to continue with an active program, subject to market
conditions, to purchase for cancellation common shares under the
Company's Normal Course Issuer Bid at or above the levels of shares
purchased in financial year 2012.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural
focuses its activities in core regions where it can own a
substantial land base and associated infrastructure. Land
inventories are maintained to enable continuous exploitation of
play types and geological trends, greatly reducing overall
exploration risk. By owning and operating associated
infrastructure, the Company is able to maximize utilization of its
production facilities, thereby increasing control over production
costs. Further, the Company maintains large project inventories and
production diversification among each of the commodities it
produces; light and medium crude oil, primary heavy crude oil,
Pelican Lake heavy crude oil, bitumen and SCO (herein collectively
referred to as "crude oil"), natural gas and NGLs. A large
diversified project portfolio enables the effective allocation of
capital to higher return opportunities.
OPERATIONS REVIEW
Activity by core region
Net unproved properties
as at Drilling activity
Dec 31, 2012 year ended
(thousands of net Dec 31, 2012
acres)(1) (net wells)(2)
----------------------------------------------------------------------------
North America
Northeast British
Columbia 2,954 20.6
Northwest Alberta 2,196 51.9
Northern Plains 6,603 984.8
Southern Plains 1,026 43.8
Southeast Saskatchewan 100 37.0
Thermal In Situ Oil
Sands 837 556.0
----------------------------------------------------------------------------
13,716 1,694.1
Oil Sands Mining and
Upgrading 59 303.0
North Sea 128 0.9
Offshore Africa 4,307 -
----------------------------------------------------------------------------
18,210 1,998.0
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Unproved land refers to a property or part of a property to
which no reserves have been specifically attributed.
(2) Drilling activity includes stratigraphic test and service
wells.
Drilling activity (number of wells)
Year Ended Dec 31
--------------------------------------
2012 2011
Gross Net Gross Net
----------------------------------------------------------------------------
Crude oil 1,255 1,203 1,159 1,103
Natural gas 42 35 102 83
Dry 34 33 49 48
----------------------------------------------------------------------------
Subtotal 1,331 1,271 1,310 1,234
Stratigraphic test / service wells 728 727 659 657
----------------------------------------------------------------------------
Total 2,059 1,998 1,969 1,891
----------------------------------------------------------------------------
Success rate (excluding stratigraphic
test / service wells) 97% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America Exploration and Production
North America crude oil and
NGLs
Three Months Ended Year Ended
------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs
production (bbl/d) 351,983 332,895 291,839 326,829 295,618
----------------------------------------------------------------------------
Net wells targeting crude
oil 313 371 345 1,236 1,147
Net successful wells
drilled 294 365 330 1,203 1,103
----------------------------------------------------------------------------
Success rate 94% 98% 96% 97% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- North America crude oil and NGLs production for the year
averaged 326,829 bbl/d representing an increase of 11% from 2011.
The increase in average yearly production was largely a result of
successful drilling programs in primary heavy and light crude
oil.
- North America crude oil and NGLs production for Q4/12 was
351,983 bbl/d. Q4/12 crude oil and NGLs production volumes
increased 21% and 6% from Q4/11 and Q3/12 levels, respectively. The
increase in production from Q4/11 was driven by higher primary
heavy crude oil and thermal production volumes.
- Primary heavy crude oil operations achieved record quarterly
production in Q4/12 of approximately 130,200 bbl/d which
contributed to 22% average annual production growth over 2011
levels. Canadian Natural executed a record drilling program of 886
net primary heavy crude oil wells in 2012.
- During 2012 the reservoir performance at Pelican Lake
demonstrated expected positive results.
-- Strong operating efficiencies were achieved at Pelican Lake
as operating costs decreased to an annual average of $11.89/bbl in
2012.
-- In Q4/12, reservoir performance remained strong with
incremental production response from the polymer flood. As
production increased to facility capacity, the ability to treat the
polymer produced was constrained. As a result, oil production at
both Pelican Lake and Woodenhouse was curtailed.
-- Construction of the new battery, targeted for completion in
June 2013, will address these temporary treatment constraints and
enable a step increase in production volumes at both Pelican Lake
and Woodenhouse. 2013 production expected for Pelican Lake remains
unchanged and is targeted to range from 46,000 bbl/d to 50,000
bbl/d.
- North America light crude oil and NGLs annual production
increased 13% in 2012 over 2011 levels as a result of a successful
drilling program consisting of 124 net light crude oil wells. In
2013, Canadian Natural targets to drill 114 net light crude oil
wells, 41 of which are targeting new play developments that were
initiated in 2012. The Company continues to advance horizontal
multi-frac well technology in pools across its land base. In
addition, 70% of targeted total drilling will be focused on
horizontal wells.
- Canadian Natural's robust portfolio of thermal in situ
projects is a significant part of the Company's defined plan to
transition to a longer-life, more sustainable asset base with the
ability to generate significant shareholder value for decades to
come. The Company targets to grow thermal in situ production to
approximately 500,000 bbl/d of capacity by delivering projects that
will add 40,000 bbl/d of production every two to three years.
-- At Primrose, total thermal operating costs including energy
costs for Q4/12 were $7.95/bbl. Annual thermal operating costs
including energy costs were $9.69/bbl. Thermal production averaged
over 120,000 bbl/d in Q4/12, representing a 19% increase from Q3/12
to Q4/12, primarily due to new pads at Primrose East entering their
production cycles. Production volumes are targeted to increase by
5% in 2013.
-- Kirby South Phase 1 is slightly ahead of plan and on budget.
All major equipment and modules have been delivered and installed
on site with overall construction progress ahead of schedule. An
update to the project at the end of Q4/12 is as follows:
--- Overall project is 81% complete.
--- Overall construction is 73% complete.
--- Drilling and Completions are 82% complete. Drilling on the
fifth of seven pads was completed in Q4/12. In early 2013 the sixth
pad was drilled and the seventh pad is currently being drilled.
--- First steam-in is targeted for Q4/13 and production is
targeted to ramp up to 40,000 bbl/d in late 2014.
-- On Kirby North Phase 1, detailed engineering is now in
progress. Construction of the main access road has been completed
and site preparation continues. A stratigraphic ("strat") drilling
program consisting of 50 wells is targeted for Q1/13. First
steam-in is targeted for 2016. Full project sanction is expected in
Q3/13.
- Planned drilling activity for 2013 includes 132 net thermal in
situ wells and 1,022 net crude oil wells, excluding strat test and
service wells.
- Canadian Natural has an active strat test well drilling
program to delineate the reservoir characteristics for future
projects. The Company targets to drill 463 strat wells in 2013.
North America natural gas
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Natural gas production
(MMcf/d) 1,113 1,169 1,255 1,198 1,231
----------------------------------------------------------------------------
Net wells targeting
natural gas 3 9 29 35 86
Net successful wells
drilled 3 9 27 35 83
----------------------------------------------------------------------------
Success rate 100% 100% 93% 100% 97%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- North America natural gas production for the year averaged
1,198 MMcf/d representing a decrease of 3% from 2011 levels. During
Q4/12, natural gas production averaged 1,113 MMcf/d representing a
decrease of 11% from Q4/11 and 5% from Q3/12. The decrease in
production levels was primarily due to expected production declines
reflecting Canadian Natural's strategic decision to allocate
capital to higher return crude oil projects. As well, the Company
shut in a cumulative total of 40 MMcf/d of natural gas volumes as a
result of weakened natural gas pricing. In Q4/12, production was
restricted after ending fixed processing agreements for certain
natural gas volumes to maintain flexible cost control in response
to weakening gas pricing.
- During 2012, due to weak natural gas pricing, Canadian Natural
reduced its capital expenditures related to natural gas. As a
result, drilling and expansion at Septimus, the Company's liquids
rich Montney play, was deferred into 2013, with the anticipation of
improved pricing. To date, the expansion is on track and is
targeted for completion in late 2013 which will increase targeted
natural gas sales levels from Septimus to 125 MMcf/d, yielding
12,200 bbl/d of liquids following processing through the plant and
deep cut facilities.
- Canadian Natural is the second largest producer of natural gas
in Canada and a significant owner and operator of natural gas
infrastructure in Western Canada. The North America Company Gross
proved plus probable natural gas reserve base of 5.57 Tcf generates
operating free cash flow and presents significant upside potential
for natural gas production and value when natural gas prices
recover.
- Canadian Natural has a dominate Montney land position with
over one million high quality net acres, the largest in the
industry. In order to maximize the value of this important asset
Canadian Natural has begun the process to monetize approximately
250,000 net acres (approximately 390 net sections) of our Montney
land base in the liquids rich fairway in the Graham Kobes area of
North East British Columbia. Under the process Canadian Natural
will consider either an outright sale of the lands or a joint
venture partner with LNG expertise to jointly develop the lands. If
this process meets our internal targets and a transaction is
completed, Canadian Natural will continue to have one of the
largest undeveloped Montney land bases in Canada with lands
contained in the two major areas of Septimus, British Columbia and
North West Alberta.
International Exploration and Production
Three Months Ended Year
Ended
-----------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil production (bbl/d)
North Sea 19,140 19,502 26,769 19,824 29,992
Offshore Africa 15,762 17,566 22,726 18,648 23,009
----------------------------------------------------------------------------
Natural gas production
(MMcf/d)
North Sea 1 2 6 2 7
Offshore Africa 20 20 19 20 19
----------------------------------------------------------------------------
Net wells targeting crude oil - - - - 0.9
Net successful wells drilled - - - - -
----------------------------------------------------------------------------
Success rate - - 0% - 0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Canadian Natural's international assets provide light crude
oil balance to the Company's diverse portfolio and generated over
$200 million of free cash flow in 2012.
- International crude oil production averaged 38,472 bbl/d
during 2012 which was within the Company's previously stated
guidance of 38,000 bbl/d - 39,000 bbl/d for the year. Production
volumes declined from 2011 as a result of the suspension of
production at Banff/Kyle (North Sea) due to storm damage in Q4/11,
maintenance activities on a third-party operated pipeline in the
North Sea, natural field declines, and planned maintenance
activities at Ninian (North Sea), Baobab and Espoir (Offshore
Africa).
- Production is targeted to increase by approximately 6% in
2013. International light oil activities in 2013 will include a
ramp up of drilling operations in the North Sea, the commencement
of abandonment operations at Murchison in the North Sea, and
commencement of the infill drilling program at Espoir, Offshore
Africa.
- The Company continues with the partnering process for South
Africa. Targeted drilling windows are from Q4/13 to Q1/14 and from
Q4/14 to Q1/15.
North America Oil Sands Mining and Upgrading - Horizon
Three Months Ended Year Ended
---------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Synthetic crude oil production
(bbl/d) 83,079 99,205 102,952 86,077 40,434
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Horizon Oil Sands achieved average annual SCO production of
86,077 bbl/d in 2012. Production volumes were 113% higher than 2011
volumes as the reliability of the Horizon plant steadily improved
in 2012.
- Average SCO production of 83,079 bbl/d was achieved at Horizon
during Q4/12. Production decreased 16% from Q3/12 as a result of
the previously announced 12 day planned proactive maintenance
activities completed in October. In late December, additional
unplanned maintenance activities were performed on the OPPs which
contributed to lower quarterly volumes.
- In January and February 2013, strong performance from Horizon
resulted in average SCO volumes of approximately 113,000 bbl/d and
107,000 bbl/d, respectively. Q1/13 production guidance is targeted
to range from 105,000 bbl/d to 111,000 bbl/d of SCO.
- The first major turnaround at Horizon is planned for May 2013.
To ensure effective execution of the turnaround and to ensure
greater reliability, the turnaround has been increased from 18 days
to 24 days. 2013 annual guidance has not been affected and remains
unchanged at 100,000 bbl/d to 108,000 bbl/d of SCO.
- Canadian Natural's staged expansion to 250,000 bbl/d of SCO
production capacity continues to progress on track. An update to
the expansion at the end of Q4/12 is as follows:
-- Overall Horizon expansion is 18% complete.
-- Reliability - Tranche 2 is 86% complete. This project is
targeted for completion in 2013; an additional of 5,000 bbl/d of
production capacity will be added at completion.
-- Directive 74 includes technological investment and research
into tailings management. This portion remains on track and is
currently 16% complete.
-- Phase 2A is the coker expansion. The expansion is 47%
complete, and is targeted to add 10,000 bbl/d of production
capacity in 2015.
-- Phase 2B is 8% complete. This phase includes lump sum
contracts for major components such as gas/oil hydrotreatment,
froth treatment and a hydrogen plant. This phase is targeted to add
another 45,000 bbl/d of production capacity in 2016.
-- Phase 3 is on track and engineering is underway. This phase
is 8% complete, and includes the addition of supplementary
extraction trains. This phase is targeted to increase production
capacity by 80,000 bbl/d in 2017.
-- Projects currently under construction are trending at or
below cost estimates.
MARKETING
Three Months Ended Year Ended
------------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and
NGLs pricing
WTI benchmark
price
(US$/bbl) (1) $ 88.20 $ 92.19 $ 94.02 $ 94.19 $ 95.14
WCS blend
differential
from WTI (%)
(2) 21% 24% 11% 22% 18%
SCO price
(US$/bbl) $ 91.90 $ 90.84 $ 102.95 $ 92.59 $ 103.63
Average
realized
pricing
before risk
management
(C$/bbl) (3) $ 64.23 $ 67.59 $ 85.28 $ 70.24 $ 77.46
Natural gas
pricing
AECO benchmark
price (C$/GJ) $ 2.89 $ 2.08 $ 3.29 $ 2.28 $ 3.48
Average
realized
pricing
before risk
management
(C$/Mcf) (3) $ 3.16 $ 2.28 $ 3.50 $ 2.44 $ 3.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) West Texas Intermediate ("WTI").
(2) Western Canadian Select ("WCS").
(3) Average crude oil and NGLs pricing excludes SCO. Pricing is
net of transportation and blending costs, excluding risk management
activities.
- The WCS heavy crude oil differential ("WCS differential") as a
percent of WTI averaged 22% during 2012 compared with 18% in 2011.
During Q4/12 the WCS differential averaged 21%, in line with the
Company's long term expectations. The Company anticipates continued
volatility in the differential for the first half of 2013 and
narrowing of the differential thereafter as additional heavy oil
conversion and pipeline capacity come on stream.
- During October and November 2012, the WCS differential
averaged 11% and 16% respectively, widening out to 34% in December
2012 as a result of unplanned pipeline capacity limitations and
refinery-planned lower crude oil inventories at year-end. During
January and February 2013, the WCS differential widened to average
37% but was partially offset by higher overall WTI pricing. For
March 2013, the WCS differential has narrowed to average 29%.
- Canadian Natural contributed 157,000 bbl/d of its heavy crude
oil stream to the WCS blend in 2012. The Company remains the
largest contributor to the WCS blend, accounting for 53%.
- During 2012, Canadian natural gas production declined in
response to lower pricing while US natural gas production remained
steady throughout the year. Natural gas pricing recovered to AECO
$2.89 in Q4/12 but benchmark pricing will continue to remain
volatile until the demand from the power generation sector
increases enough to offset strong North American supply.
NORTH WEST REDWATER UPGRADING AND REFINING
During Q4/12, the Redwater Partnership 50,000 bbl/d bitumen
refinery (78,000 bbl/d of bitumen blend) was sanctioned by its
owners (50% Canadian Natural). Work continues on the North West
Redwater refinery and completion is targeted for mid-2016. The
Company will also provide 12,500 bbl/d of bitumen feedstock to the
refinery as a toll payer. There is potential to further expand the
downstream capacity of the North West Redwater refinery from its
50,000 bbl/d of bitumen facility capacity in Phase 1 to 150,000
bbl/d of bitumen facility capacity.
The North West Redwater refinery asset strengthens the Company's
position by providing a competitive return on investment and by
adding 50,000 bbl/d of bitumen conversion capacity in Alberta which
will help reduce volatility in pricing all Western Canadian heavy
crude oil.
FINANCIAL REVIEW
The Company continues to implement proven strategies and focuses
on disciplined capital allocation. As a result, the financial
position of Canadian Natural remains strong. Canadian Natural's
cash flow generation, credit facilities, diverse asset base and
related capital expenditure programs, and commodity hedging policy
all support a flexible financial position and provide the right
financial resources for the near, mid and long term.
- The Company's strategy is to maintain a diverse portfolio
balanced across various commodity types. The Company achieved
production of 658,973 BOE/d for Q4/12 with over 97% of production
located in G8 countries.
- Canadian Natural has a strong balance sheet with debt to book
capitalization of 26.0% and debt to EBITDA of 1.2x. At December 31,
2012, long-term debt amounted to $8.7 billion compared with $8.6
billion at December 31, 2011.
- Canadian Natural maintains significant financial stability and
liquidity represented by approximately $3.66 billion in available
unused bank lines at the end of the 2012.
- The Company's commodity hedging program protects investment
returns, ensures ongoing balance sheet strength and supports the
Company's cash flow for its capital expenditures programs. Through
the use of collars, the Company has hedged 48% of its forecasted
2013 crude oil volumes; 200,000 bbl/d of crude oil volumes in
Q1/13, and 250,000 bbl/d of crude oil volumes in Q2/13, Q3/13 and
Q4/13. Details of the Company's commodity hedging program can be
found on the Company's website at www.cnrl.com.
- During 2012, Canadian Natural purchased 11,012,700 common
shares for cancellation at a weighted average price of $28.91 per
common share.
- For 2013, the Board has approved a 19% dividend increase to
C$0.125 per quarter, C$0.50 per share annualized. This will be the
thirteenth consecutive year that the Company has announced an
increased annual dividend distribution representing a compound
annual growth rate of 21% over the period.
- In addition, the Company's Board of Directors have directed
Management to continue with an active program, subject to market
conditions, to purchase for cancellation common shares under the
Company's Normal Course Issuer Bid at or above the levels of shares
purchased in financial year 2012.
OUTLOOK
The Company forecasts 2013 production levels before royalties to
average between 1,085 and 1,145 MMcf/d of natural gas and between
482,000 and 513,000 bbl/d of crude oil and NGLs. Q1/13 production
guidance before royalties is forecast to average between 1,130 and
1,150 MMcf/d of natural gas and between 471,000 and 495,000 bbl/d
of crude oil and NGLs. Detailed guidance on production levels,
capital allocation and operating costs can be found on the
Company's website at www.cnrl.com.
CORPORATE ANNOUNCEMENTS
Board of Directors Changes
James S. Palmer has informed the Company of his decision after
16 years of continuous service as a Director, to not stand for
re-election to the Board of Directors at the Annual and Special
Meeting of Shareholder on May 2, 2013. During Mr. Palmer's tenure
with the Company, Canadian Natural has transitioned from a
conventional oil and natural gas player based in western Canada to
one of the largest independent crude oil and natural gas producers
in the world with both domestic and international operations.
Canadian Natural and the Board would like to thank Mr. Palmer for
his valued wisdom, insight, guidance, leadership and dedication to
the Company and its shareholders since his appointment as a
director in 1997.
Management Changes
John G. Langille, Vice-Chairman, has announced his decision to
retire from Canadian Natural effective May 2, 2013 immediately
following the Annual and Special Meeting of Shareholders. John has
served Canadian Natural for 37 years in various roles, most
recently in the capacity of Vice-Chairman and prior to that as
President. Through John's untiring efforts and guidance, Canadian
Natural has remained focused on our defined growth plan thereby
creating value for our shareholders through targeting cost
effective alternatives to developing our portfolio of projects and
to being one of the most effective and efficient producers in our
industry. Canadian Natural and the Board would like to thank John
for his dedicated service and loyalty to the Company.
As part of the Canadian Natural's management stewardship, high
priority is assigned to succession planning to ensure the continued
strength of the Company's leadership team.
Tim S. McKay, currently Chief Operating Officer, will become
Executive Vice-President and Chief Operating Officer. He will
continue to be responsible for the Canadian Conventional and
International operations, and in addition will now be responsible
for Horizon operations.
Douglas A. Proll, currently Chief Financial Officer and Senior
Vice-President, Finance will become Executive Vice-President. He
will continue to be a senior member of the Company's Management
Committee and will have direct responsibility for certain
non-financial departments and provide additional leadership in
Investor Relations and other areas of stakeholder relations.
Corey B. Bieber, Vice-President Finance and Investor Relations
will assume the role of Chief Financial Officer and Senior
Vice-President, Finance. Corey joined Canadian Natural in 2001 and
has been responsible for Treasury and Investor Relations since then
and became a member of the Company's Management Committee in 2009.
In his new role, Corey will be responsible for all aspects of the
finance functions at Canadian Natural.
The appointments of Mr. McKay, Mr. Bieber and Mr. Proll are
effective March 28, 2013.
YEAR-END RESERVES
Determination of Reserves
For the year ended December 31, 2012 the Company retained
Independent Qualified Reserves Evaluators ("Evaluators"), Sproule
Associates Limited, Sproule International Limited (together as
"Sproule") and GLJ Petroleum Consultants Ltd. ("GLJ"), to evaluate
and review all of the Company's proved and proved plus probable
reserves. Sproule evaluated the Company's North America and
International crude oil, bitumen, natural gas and NGL reserves. GLJ
evaluated the Company's Horizon synthetic crude oil reserves. The
Evaluators conducted the evaluation and review in accordance with
the standards contained in the Canadian Oil and Gas Evaluation
Handbook ("COGE Handbook"). The reserves disclosure is presented in
accordance with NI 51-101 requirements using forecast prices and
escalated costs.
The Reserves Committee of the Company's Board of Directors has
met with and carried out independent due diligence procedures with
the Evaluators as to the Company's reserves.
Corporate Total
- Company Gross proved crude oil, SCO, bitumen and NGL reserves
increased 6% to 4.33 billion barrels. Company Gross proved natural
gas reserves decreased 7% to 4.14 Tcf. Total proved reserves
increased 4% to 5.02 billion BOE.
- Company Gross proved plus probable crude oil, SCO, bitumen and
NGL reserves increased 6% to 6.92 billion barrels. Company Gross
proved plus probable natural gas reserves decreased 5% to 5.79 Tcf.
Total proved plus probable reserves increased 5% to 7.89 billion
BOE.
- Company Gross proved reserve additions, including
acquisitions, were 404 million barrels of crude oil, SCO, bitumen
and NGL and 135 billion cubic feet of natural gas for 426 million
BOE. The total proved reserve replacement ratio was 178%. The total
proved reserve life index is 22.8 years.
- Company Gross proved plus probable reserve additions,
including acquisitions, were 565 million barrels of crude oil,
bitumen, SCO and NGL and 132 billion cubic feet of natural gas for
587 million BOE. The total proved plus probable reserve replacement
ratio was 246%. The total proved plus probable reserve life index
is 35.8 years.
- Proved undeveloped crude oil, SCO, bitumen and NGL reserves
accounted for 31% of the corporate total proved reserves and proved
undeveloped natural gas reserves accounted for 4% of the corporate
total proved reserves.
North America Exploration and Production
- North America Company Gross proved crude oil, bitumen and NGL
reserves increased 7% to 1.74 billion barrels. Company Gross proved
natural gas reserves decreased 7% to 3.99 Tcf. Total proved BOE
increased 3% to 2.41 billion barrels.
- North America Company Gross proved plus probable crude oil,
bitumen and NGL reserves increased 16% to 3.08 billion barrels.
Company Gross proved plus probable natural gas reserves decreased
5% to 5.57 Tcf. Total proved plus probable BOE increased 11% to
4.01 billion barrels.
- North America Company Gross proved reserve additions and
revisions, including acquisitions, were 230 million barrels of
crude oil, bitumen and NGL and 157 billion cubic feet of natural
gas for 256 million BOE. The total proved reserve replacement ratio
is 133%. The total proved reserve life index in 14.3 years.
- North America Company Gross proved plus probable reserve
additions and revisions, including acquisitions, were 548 million
barrels of crude oil, bitumen and NGL and 174 billion cubic feet of
natural gas for 577 million BOE. The total proved plus probable
reserve replacement ratio was 299%. The total proved plus probable
reserve life index is 23.8 years.
- Proved undeveloped crude oil, bitumen and NGL reserves
accounted for 38% of the North America total proved reserves and
proved undeveloped natural gas reserves accounted for 8% of the
North America total proved reserves.
- Thermal oil Company Gross proved reserves increased 9% to
1,066 million barrels primarily due to category transfers from
probable undeveloped to proved undeveloped at Kirby North and new
proved undeveloped additions at Primrose and Wolf Lake. Proved
bitumen reserve additions and revisions were 128 million barrels.
Total proved plus probable bitumen reserves increased 23% to 2,122
million barrels primarily due to proved plus probable undeveloped
additions at Primrose and Wolf Lake and probable undeveloped
additions at Grouse.
- Company Gross proved plus probable bitumen reserves additions
and revisions were 432 million barrels.
North America Oil Sands Mining and Upgrading
- Company Gross proved synthetic crude oil reserves increased 6%
to 2.26 billion barrels.
- Proved reserve additions were 167 million barrels primarily
due to additional stratigraphic wells drilled in the north pit.
International Exploration and Production
- North Sea Company Gross proved reserves decreased 2% to 240
million BOE primarily due to production. North Sea Company Gross
proved plus probable reserves are 349 million BOE.
- Offshore Africa Company Gross proved reserves decreased 7% to
115 million BOE primarily due to production. Offshore Africa
Company Gross proved plus probable reserves are 177 million
BOE.
Summary of Company Gross Crude Oil, Bitumen, Natural Gas &
NGL Reserves
As of December 31, 2012
Forecast Prices and Costs
Pelican Bitumen
Light and Primary Lake (Thermal
Medium Oil Heavy Oil Heavy Oil Oil)
MMbbl MMbbl MMbbl MMbbl
----------------------------------------------------------------------------
North America
Proved
Developed Producing 92 85 217 238
Developed Non-Producing 2 23 11 104
Undeveloped 19 96 39 724
----------------------------------------------------------------------------
Total Proved 113 204 267 1,066
Probable 51 80 105 1,056
----------------------------------------------------------------------------
Total Proved plus Probable 164 284 372 2,122
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
Proved
Developed Producing 49
Developed Non-Producing 14
Undeveloped 164
----------------------------------------------------------------------------
Total Proved 227
Probable 105
----------------------------------------------------------------------------
Total Proved plus Probable 332
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
Proved
Developed Producing 65
Developed Non-Producing -
Undeveloped 38
----------------------------------------------------------------------------
Total Proved 103
Probable 55
----------------------------------------------------------------------------
Total Proved plus Probable 158
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
Proved
Developed Producing 206 85 217 238
Developed Non-Producing 16 23 11 104
Undeveloped 221 96 39 724
----------------------------------------------------------------------------
Total Proved 443 204 267 1,066
Probable 211 80 105 1,056
----------------------------------------------------------------------------
Total Proved plus Probable 654 284 372 2,122
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Barrels of
Synthetic Natural Gas Oil
Crude Oil Natural Liquids Equivalent
MMbbl Gas Bcf MMbbl MMBOE
---------------------------------------------------------------------------
North America
Proved
Developed Producing 1,837 2,664 53 2,966
Developed Non-Producing - 213 3 178
Undeveloped 418 1,108 38 1,519
---------------------------------------------------------------------------
Total Proved 2,255 3,985 94 4,663
Probable 1,096 1,589 44 2,697
---------------------------------------------------------------------------
Total Proved plus Probable 3,351 5,574 138 7,360
---------------------------------------------------------------------------
---------------------------------------------------------------------------
North Sea
Proved
Developed Producing 3 49
Developed Non-Producing 55 23
Undeveloped 24 168
---------------------------------------------------------------------------
Total Proved 82 240
Probable 20 109
---------------------------------------------------------------------------
Total Proved plus Probable 102 349
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Offshore Africa
Proved
Developed Producing 56 75
Developed Non-Producing - -
Undeveloped 13 40
---------------------------------------------------------------------------
Total Proved 69 115
Probable 42 62
---------------------------------------------------------------------------
Total Proved plus Probable 111 177
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total Company
Proved
Developed Producing 1,837 2,723 53 3,090
Developed Non-Producing - 268 3 201
Undeveloped 418 1,145 38 1,727
---------------------------------------------------------------------------
Total Proved 2,255 4,136 94 5,018
Probable 1,096 1,651 44 2,868
---------------------------------------------------------------------------
Total Proved plus Probable 3,351 5,787 138 7,886
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Summary of Company Net Crude Oil, Bitumen, Natural Gas & NGL
Reserves
As of December 31, 2012
Forecast Prices and Costs
Pelican Bitumen
Light and Primary Lake (Thermal
Medium Oil Heavy Oil Heavy Oil Oil)
MMbbl MMbbl MMbbl MMbbl
----------------------------------------------------------------------------
North America
Proved
Developed Producing 81 71 170 179
Developed Non-Producing 1 19 10 83
Undeveloped 16 82 32 564
----------------------------------------------------------------------------
Total Proved 98 172 212 826
Probable 42 64 75 801
----------------------------------------------------------------------------
Total Proved plus Probable 140 236 287 1,627
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
Proved
Developed Producing 49
Developed Non-Producing 14
Undeveloped 164
----------------------------------------------------------------------------
Total Proved 227
Probable 105
----------------------------------------------------------------------------
Total Proved plus Probable 332
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
Proved
Developed Producing 55
Developed Non-Producing 0
Undeveloped 30
----------------------------------------------------------------------------
Total Proved 85
Probable 42
----------------------------------------------------------------------------
Total Proved plus Probable 127
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
Proved
Developed Producing 185 71 170 179
Developed Non-Producing 15 19 10 83
Undeveloped 210 82 32 564
----------------------------------------------------------------------------
Total Proved 410 172 212 826
Probable 189 64 75 801
----------------------------------------------------------------------------
Total Proved plus Probable 599 236 287 1,627
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Barrels of
Synthetic Natural Gas Oil
Crude Oil Natural Liquids Equivalent
MMbbl Gas Bcf MMbbl MMBOE
---------------------------------------------------------------------------
North America
Proved
Developed Producing 1,516 2,394 37 2,453
Developed Non-Producing - 178 2 145
Undeveloped 375 968 30 1,260
---------------------------------------------------------------------------
Total Proved 1,891 3,540 69 3,858
Probable 835 1,367 34 2,079
---------------------------------------------------------------------------
Total Proved plus Probable 2,726 4,907 103 5,937
---------------------------------------------------------------------------
---------------------------------------------------------------------------
North Sea
Proved
Developed Producing 3 49
Developed Non-Producing 55 23
Undeveloped 24 168
---------------------------------------------------------------------------
Total Proved 82 240
Probable 20 109
---------------------------------------------------------------------------
Total Proved plus Probable 102 349
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Offshore Africa
Proved
Developed Producing 39 61
Developed Non-Producing - -
Undeveloped 9 32
---------------------------------------------------------------------------
Total Proved 48 93
Probable 28 47
---------------------------------------------------------------------------
Total Proved plus Probable 76 140
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total Company
Proved
Developed Producing 1,516 2,436 37 2,563
Developed Non-Producing - 233 2 168
Undeveloped 375 1,001 30 1,460
---------------------------------------------------------------------------
Total Proved 1,891 3,670 69 4,191
Probable 835 1,415 34 2,235
---------------------------------------------------------------------------
Total Proved plus Probable 2,726 5,085 103 6,426
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Reconciliation of Company Gross Reserves by Product
As of December 31, 2012
Forecast Prices and Costs
PROVED
Pelican Bitumen
Light and Primary Lake (Thermal
North America Medium Oil Heavy Oil Heavy Oil Oil)
MMbbl MMbbl MMbbl MMbbl
----------------------------------------------------------------------------
December 31, 2011 114 175 276 974
----------------------------------------------------------------------------
Discoveries - - - -
Extensions 4 24 1 68
Infill Drilling 5 20 - 10
Improved Recovery - - 5 -
Acquisitions 1 - - -
Dispositions - - - -
Economic Factors - - - -
Technical Revisions 4 31 (1) 50
Production (15) (46) (14) (36)
----------------------------------------------------------------------------
December 31, 2012 113 204 267 1,066
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
----------------------------------------------------------------------------
December 31, 2011 228
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling -
Improved Recovery -
Acquisitions -
Dispositions -
Economic Factors 4
Technical Revisions 2
Production (7)
----------------------------------------------------------------------------
December 31, 2012 227
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
----------------------------------------------------------------------------
December 31, 2011 109
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling 1
Improved Recovery -
Acquisitions -
Dispositions -
Economic Factors -
Technical Revisions -
Production (7)
----------------------------------------------------------------------------
December 31, 2012 103
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
----------------------------------------------------------------------------
December 31, 2011 451 175 276 974
----------------------------------------------------------------------------
Discoveries - - - -
Extensions 4 24 1 68
Infill Drilling 6 20 - 10
Improved Recovery - - 5 -
Acquisitions 1 - - -
Dispositions - - - -
Economic Factors 4 - - -
Technical Revisions 6 31 (1) 50
Production (29) (46) (14) (36)
----------------------------------------------------------------------------
December 31, 2012 443 204 267 1,066
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PROVED
Barrels of
Synthetic Natural Gas Oil
North America Crude Oil Natural Liquids Equivalent
MMbbl Gas Bcf MMbbl MMBOE
---------------------------------------------------------------------------
December 31, 2011 2,119 4,266 95 4,464
---------------------------------------------------------------------------
Discoveries - 6 - 1
Extensions - 52 2 107
Infill Drilling - 16 1 39
Improved Recovery - - - 5
Acquisitions - 43 1 9
Dispositions - (1) - -
Economic Factors 14 (38) (1) 7
Technical Revisions 153 79 5 255
Production (31) (438) (9) (224)
---------------------------------------------------------------------------
December 31, 2012 2,255 3,985 94 4,663
---------------------------------------------------------------------------
---------------------------------------------------------------------------
North Sea
---------------------------------------------------------------------------
December 31, 2011 98 244
---------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - -
Improved Recovery - -
Acquisitions - -
Dispositions - -
Economic Factors 1 4
Technical Revisions (16) (1)
Production (1) (7)
---------------------------------------------------------------------------
December 31, 2012 82 240
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Offshore Africa
---------------------------------------------------------------------------
December 31, 2011 83 123
---------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - 1
Improved Recovery - -
Acquisitions - -
Dispositions - -
Economic Factors - -
Technical Revisions (7) (1)
Production (7) (8)
---------------------------------------------------------------------------
December 31, 2012 69 115
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total Company
---------------------------------------------------------------------------
December 31, 2011 2,119 4,447 95 4,831
---------------------------------------------------------------------------
Discoveries - 6 - 1
Extensions - 52 2 107
Infill Drilling - 16 1 40
Improved Recovery - - - 5
Acquisitions - 43 1 9
Dispositions - (1) - -
Economic Factors 14 (37) (1) 11
Technical Revisions 153 56 5 253
Production (31) (446) (9) (239)
---------------------------------------------------------------------------
December 31, 2012 2,255 4,136 94 5,018
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Reconciliation of Company Gross Reserves by Product
As of December 31, 2012
Forecast Prices and Costs
PROBABLE
Pelican Bitumen
Light and Primary Lake (Thermal
North America Medium Oil Heavy Oil Heavy Oil Oil)
MMbbl MMbbl MMbbl MMbbl
----------------------------------------------------------------------------
December 31, 2011 41 74 112 752
----------------------------------------------------------------------------
Discoveries - - - -
Extensions 4 10 - 277
Infill Drilling 6 8 - 5
Improved Recovery - - 3 -
Acquisitions - - - -
Dispositions - - - -
Economic Factors - - - -
Technical Revisions - (12) (10) 22
Production - - - -
----------------------------------------------------------------------------
December 31, 2012 51 80 105 1,056
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
----------------------------------------------------------------------------
December 31, 2011 121
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling -
Improved Recovery -
Acquisitions -
Dispositions -
Economic Factors (4)
Technical Revisions (12)
Production -
----------------------------------------------------------------------------
December 31, 2012 105
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
----------------------------------------------------------------------------
December 31, 2011 56
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling 1
Improved Recovery -
Acquisitions -
Dispositions -
Economic Factors -
Technical Revisions (2)
Production -
----------------------------------------------------------------------------
December 31, 2012 55
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
----------------------------------------------------------------------------
December 31, 2011 218 74 112 752
----------------------------------------------------------------------------
Discoveries - - - -
Extensions 4 10 - 277
Infill Drilling 7 8 - 5
Improved Recovery - - 3 -
Acquisitions - - - -
Dispositions - - - -
Economic Factors (4) - - -
Technical Revisions (14) (12) (10) 22
Production - - - -
----------------------------------------------------------------------------
December 31, 2012 211 80 105 1,056
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PROBABLE
Barrels of
Synthetic Natural Gas Oil
North America Crude Oil Natural Liquids Equivalent
MMbbl Gas Bcf MMbbl MMBOE
---------------------------------------------------------------------------
December 31, 2011 1,236 1,572 39 2,516
---------------------------------------------------------------------------
Discoveries - 5 - 1
Extensions - 38 3 301
Infill Drilling - 10 - 20
Improved Recovery - - - 3
Acquisitions - 15 - 3
Dispositions - (2) - (1)
Economic Factors (11) (2) - (11)
Technical Revisions (129) (47) 2 (135)
Production - - - -
---------------------------------------------------------------------------
December 31, 2012 1,096 1,589 44 2,697
---------------------------------------------------------------------------
---------------------------------------------------------------------------
North Sea
---------------------------------------------------------------------------
December 31, 2011 36 127
---------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - -
Improved Recovery - -
Acquisitions - -
Dispositions - -
Economic Factors (1) (4)
Technical Revisions (15) (14)
Production - -
---------------------------------------------------------------------------
December 31, 2012 20 109
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Offshore Africa
---------------------------------------------------------------------------
December 31, 2011 46 64
---------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - 1
Improved Recovery - -
Acquisitions - -
Dispositions - -
Economic Factors - -
Technical Revisions (4) (3)
Production - -
---------------------------------------------------------------------------
December 31, 2012 42 62
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total Company
---------------------------------------------------------------------------
December 31, 2011 1,236 1,654 39 2,707
---------------------------------------------------------------------------
Discoveries - 5 - 1
Extensions - 38 3 301
Infill Drilling - 10 - 21
Improved Recovery - - 3
Acquisitions - 15 - 3
Dispositions - (2) - (1)
Economic Factors (11) (3) - (15)
Technical Revisions (129) (66) 2 (152)
Production - - - -
---------------------------------------------------------------------------
December 31, 2012 1,096 1,651 44 2,868
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Reconciliation of Company Gross Reserves by Product
As of December 31, 2012
Forecast Prices and Costs
PROVED PLUS PROBABLE
Pelican Bitumen
Light and Primary Lake (Thermal
North America Medium Oil Heavy Oil Heavy Oil Oil)
MMbbl MMbbl MMbbl MMbbl
----------------------------------------------------------------------------
December 31, 2011 155 249 388 1,726
----------------------------------------------------------------------------
Discoveries - - - -
Extensions 8 34 1 345
Infill Drilling 11 28 - 15
Improved Recovery - - 8 -
Acquisitions 1 - - -
Dispositions - - - -
Economic Factors - - - -
Technical Revisions 4 19 (11) 72
Production (15) (46) (14) (36)
----------------------------------------------------------------------------
December 31, 2012 164 284 372 2,122
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North Sea
----------------------------------------------------------------------------
December 31, 2011 349
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling -
Improved Recovery -
Acquisitions -
Dispositions -
Economic Factors -
Technical Revisions (10)
Production (7)
----------------------------------------------------------------------------
December 31, 2012 332
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Offshore Africa
----------------------------------------------------------------------------
December 31, 2011 165
----------------------------------------------------------------------------
Discoveries -
Extensions -
Infill Drilling 2
Improved Recovery -
Acquisitions -
Dispositions -
Economic Factors -
Technical Revisions (2)
Production (7)
----------------------------------------------------------------------------
December 31, 2012 158
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Company
----------------------------------------------------------------------------
December 31, 2011 669 249 388 1,726
----------------------------------------------------------------------------
Discoveries - - - -
Extensions 8 34 1 345
Infill Drilling 13 28 - 15
Improved Recovery - - 8 -
Acquisitions 1 - - -
Dispositions - - - -
Economic Factors - - - -
Technical Revisions (8) 19 (11) 72
Production (29) (46) (14) (36)
----------------------------------------------------------------------------
December 31, 2012 654 284 372 2,122
----------------------------------------------------------------------------
----------------------------------------------------------------------------
PROVED PLUS PROBABLE
Barrels of
Synthetic Natural Gas Oil
North America Crude Oil Natural Liquids Equivalent
MMbbl Gas Bcf MMbbl MMBOE
---------------------------------------------------------------------------
December 31, 2011 3,355 5,838 134 6,980
---------------------------------------------------------------------------
Discoveries - 11 - 2
Extensions - 90 5 408
Infill Drilling - 26 1 59
Improved Recovery - - - 8
Acquisitions - 58 1 12
Dispositions - (3) - (1)
Economic Factors 3 (40) (1) (4)
Technical Revisions 24 32 7 120
Production (31) (438) (9) (224)
---------------------------------------------------------------------------
December 31, 2012 3,351 5,574 138 7,360
---------------------------------------------------------------------------
---------------------------------------------------------------------------
North Sea
---------------------------------------------------------------------------
December 31, 2011 134 371
---------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - -
Improved Recovery - -
Acquisitions - -
Dispositions - -
Economic Factors - -
Technical Revisions (31) (15)
Production (1) (7)
---------------------------------------------------------------------------
December 31, 2012 102 349
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Offshore Africa
---------------------------------------------------------------------------
December 31, 2011 129 187
---------------------------------------------------------------------------
Discoveries - -
Extensions - -
Infill Drilling - 2
Improved Recovery - -
Acquisitions - -
Dispositions - -
Economic Factors - -
Technical Revisions (11) (4)
Production (7) (8)
---------------------------------------------------------------------------
December 31, 2012 111 177
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Total Company
---------------------------------------------------------------------------
December 31, 2011 3,355 6,101 134 7,538
---------------------------------------------------------------------------
Discoveries - 11 - 2
Extensions - 90 5 408
Infill Drilling - 26 1 61
Improved Recovery - - - 8
Acquisitions - 58 1 12
Dispositions - (3) - (1)
Economic Factors 3 (40) (1) (4)
Technical Revisions 24 (10) 7 101
Production (31) (446) (9) (239)
---------------------------------------------------------------------------
December 31, 2012 3,351 5,787 138 7,886
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) Company Gross reserves are working interest share before
deduction of royalties and excluding any royalty interests.
(2) Company Net reserves are working interest share after
deduction of royalties and including any royalty interests.
(3) Forecast pricing assumptions utilized by the independent
qualified reserves evaluators in the reserve estimates were
provided by Sproule Associates Limited:
Average
annual
increase
2013 2014 2015 2016 2017 thereafter
----------------------------------------------------------------------------
Crude oil and
NGLs
WTI at
Cushing
(US$/bbl) $ 89.63 $ 89.93 $ 88.29 $ 95.52 $ 96.96 1.5%
Western
Canada
Select
(C$/bbl) $ 69.33 $ 74.57 $ 73.21 $ 80.17 $ 81.37 1.5%
Edmonton Par
(C$/bbl) $ 84.55 $ 89.84 $ 88.21 $ 95.43 $ 96.87 1.5%
Edmonton
Pentanes+
(C$/bbl) $ 90.53 $ 96.19 $ 94.44 $ 102.18 $ 103.71 1.5%
North Sea
Brent
(US$/bbl) $ 106.42 $ 101.65 $ 97.56 $ 105.07 $ 106.65 1.5%
----------------------------------------------------------------------------
Natural gas
AECO
(C$/MMBtu) $ 3.31 $ 3.72 $ 3.91 $ 4.70 $ 5.32 1.5%
BC Westcoast
Station 2
(C$/MMBtu) $ 3.25 $ 3.66 $ 3.85 $ 4.64 $ 5.26 1.5%
Henry Hub
Louisiana
(US$/MMBtu) $ 3.65 $ 4.06 $ 4.24 $ 5.04 $ 5.66 1.5%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
A foreign exchange rate of 1.001 US$/Cdn$ was used in the 2012
evaluation.
(4) Reserve additions are comprised of all categories of Company
Gross reserve changes, exclusive of production.
(5) Reserve replacement ratio is the Company Gross reserve
additions divided by the Company Gross production in the same
period.
(6) A barrel of oil equivalent ("BOE") is derived by converting
six thousand cubic feet of natural gas to one barrel of crude oil
(6 Mcf:1 bbl). This conversion may be misleading, particularly if
used in isolation, since the 6 Mcf:1 bbl ratio is based on an
energy equivalency conversion method primarily applicable at the
burner tip and does not represent a value equivalency at the
wellhead. In comparing the value ratio using current crude oil
prices relative to natural gas prices, the 6 Mcf:1 bbl conversion
ratio may be misleading as an indication of value.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources
Limited (the "Company") in this document or documents incorporated
herein by reference constitute forward-looking statements or
information (collectively referred to herein as "forward-looking
statements") within the meaning of applicable securities
legislation. Forward-looking statements can be identified by the
words "believe", "anticipate", "expect", "plan", "estimate",
"target", "continue", "could", "intend", "may", "potential",
"predict", "should", "will", "objective", "project", "forecast",
"goal", "guidance", "outlook", "effort", "seeks", "schedule",
"proposed" or expressions of a similar nature suggesting future
outcome or statements regarding an outlook. Disclosure related to
expected future commodity pricing, forecast or anticipated
production volumes, royalties, operating costs, capital
expenditures, income tax expenses and other guidance provided
throughout this Management's Discussion and Analysis ("MD&A"),
constitute forward-looking statements. Disclosure of plans relating
to and expected results of existing and future developments,
including but not limited to the Horizon Oil Sands operations and
future expansions, Primrose thermal projects, Pelican Lake water
and polymer flood project, the Kirby Thermal Oil Sands Project,
construction of the proposed Keystone XL Pipeline from Hardisty,
Alberta to the US Gulf Coast, the proposed Kinder Morgan Trans
Mountain pipeline expansion from Edmonton, Alberta to Vancouver,
British Columbia, and the construction and future operations of the
North West Redwater bitumen upgrader and refinery also constitute
forward-looking statements. This forward-looking information is
based on annual budgets and multi-year forecasts, and is reviewed
and revised throughout the year as necessary in the context of
targeted financial ratios, project returns, product pricing
expectations and balance in project risk and time horizons. These
statements are not guarantees of future performance and are subject
to certain risks. The reader should not place undue reliance on
these forward-looking statements as there can be no assurances that
the plans, initiatives or expectations upon which they are based
will occur.
In addition, statements relating to "reserves" are deemed to be
forward-looking statements as they involve the implied assessment
based on certain estimates and assumptions that the reserves
described can be profitably produced in the future. There are
numerous uncertainties inherent in estimating quantities of proved
and proved plus probable crude oil, natural gas and natural gas
liquids ("NGLs") reserves and in projecting future rates of
production and the timing of development expenditures. The total
amount or timing of actual future production may vary significantly
from reserve and 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, 2012 and the MD&A and the
audited consolidated financial statements for the year ended
December 31, 2011.
All dollar amounts are referenced in millions of Canadian
dollars, except where noted otherwise. The Company's consolidated
financial statements for the period ended December 31, 2012 and
this MD&A have been prepared in accordance with International
Financial Reporting Standards ("IFRS") as issued by the
International Accounting Standards Board. This MD&A includes
references to financial measures commonly used in the crude oil and
natural gas industry, such as adjusted net earnings from
operations, cash flow from operations, and cash production costs.
These financial measures are not defined by IFRS and therefore are
referred to as non-GAAP measures. The non-GAAP measures used by the
Company may not be comparable to similar measures presented by
other companies. The Company uses these non-GAAP measures to
evaluate its performance. The non-GAAP measures should not be
considered an alternative to or more meaningful than net earnings,
as determined in accordance with IFRS, as an indication of the
Company's performance. The non-GAAP measures adjusted net earnings
from operations and cash flow from operations are reconciled to net
earnings, as determined in accordance with IFRS, in the "Financial
Highlights" section of this MD&A. The derivation of cash
production costs is included in the "Operating Highlights - Oil
Sands Mining and Upgrading" section of this MD&A. The Company
also presents certain non-GAAP financial ratios and their
derivation in the "Liquidity and Capital Resources" section of this
MD&A.
A Barrel of Oil Equivalent ("BOE") is derived by converting six
thousand cubic feet ("Mcf") of natural gas to one barrel ("bbl") of
crude oil (6 Mcf:1 bbl). This conversion may be misleading,
particularly if used in isolation, since the 6 Mcf:1 bbl ratio is
based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value
equivalency at the wellhead. In comparing the value ratio using
current crude oil prices relative to natural gas prices, the 6
Mcf:1 bbl conversion ratio may be misleading as an indication of
value. In addition, for the purposes of this MD&A, crude oil is
defined to include the following commodities: light and medium
crude oil, primary heavy crude oil, Pelican Lake heavy crude oil,
bitumen (thermal oil), and synthetic crude oil.
Production volumes and per unit statistics are presented
throughout this MD&A on a "before royalty" or "gross" basis,
and realized prices are net of transportation and blending costs
and exclude the effect of risk management activities. Production on
an "after royalty" or "net" basis is also presented for information
purposes only.
The following discussion refers primarily to the Company's
financial results for the three months and year ended December 31,
2012 in relation to the comparable periods in 2011 and the third
quarter of 2012. The accompanying tables form an integral part of
this MD&A. Additional information relating to the Company,
including its Annual Information Form for the year ended December
31, 2011, is available on SEDAR at www.sedar.com, and on EDGAR at
www.sec.gov. This MD&A is dated March 6, 2013.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Product sales $ 4,059 $ 3,978 $ 4,788 $ 16,195 $ 15,507
Net earnings $ 352 $ 360 $ 832 $ 1,892 $ 2,643
Per common share -
basic $ 0.32 $ 0.33 $ 0.76 $ 1.72 $ 2.41
- diluted $ 0.32 $ 0.33 $ 0.76 $ 1.72 $ 2.40
Adjusted net earnings
from operations (1) $ 359 $ 353 $ 972 $ 1,618 $ 2,540
Per common share -
basic $ 0.33 $ 0.33 $ 0.89 $ 1.48 $ 2.32
- diluted $ 0.33 $ 0.32 $ 0.88 $ 1.47 $ 2.30
Cash flow from
operations (2) $ 1,548 $ 1,431 $ 2,158 $ 6,013 $ 6,547
Per common share -
basic $ 1.41 $ 1.31 $ 1.97 $ 5.48 $ 5.98
- diluted $ 1.41 $ 1.30 $ 1.96 $ 5.47 $ 5.94
Capital expenditures,
net of dispositions $ 1,767 $ 1,621 $ 1,909 $ 6,308 $ 6,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Adjusted net earnings from operations is a non-GAAP measure
that represents net earnings adjusted for certain items of a
non-operational nature. The Company evaluates its performance based
on adjusted net earnings from operations. The reconciliation
"Adjusted Net Earnings from Operations" presented below lists the
after-tax effects of certain items of a non-operational nature that
are included in the Company's financial results. Adjusted net
earnings from operations may not be comparable to similar measures
presented by other companies.
(2) Cash flow from operations is a non-GAAP measure that
represents net earnings adjusted for non-cash items before working
capital adjustments. The Company evaluates its performance based on
cash flow from operations. The Company considers cash flow from
operations a key measure as it demonstrates the Company's ability
to generate the cash flow necessary to fund future growth through
capital investment and to repay debt. The reconciliation "Cash Flow
from Operations" presented lists certain non-cash items that are
included in the Company's financial results. Cash flow from
operations may not be comparable to similar measures presented by
other companies.
Adjusted Net Earnings from Operations
Three Months Ended Year Ended
------------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings as
reported $ 352 $ 360 $ 832 $ 1,892 $ 2,643
Share-based
compensation,
net of tax (1) (41) 49 207 (214) (102)
Unrealized risk
management loss
(gain), net of
tax (2) 4 22 50 (37) (95)
Unrealized
foreign
exchange loss
(gain), net of
tax (3) 254 (136) (117) 129 215
Realized foreign
exchange gain
on repayment of
US dollar debt
securities (4) (210) - - (210) (225)
Effect of
statutory tax
rate and other
legislative
changes on
deferred income
tax liabilities
(5) - 58 - 58 104
----------------------------------------------------------------------------
Adjusted net
earnings from
operations $ 359 $ 353 $ 972 $ 1,618 $ 2,540
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company's employee stock option plan provides for a cash
payment option. Accordingly, the fair value of the outstanding
vested options is recorded as a liability on the Company's balance
sheets and periodic changes in the fair value are recognized in net
earnings or are capitalized to Oil Sands Mining and Upgrading
construction costs.
(2) Derivative financial instruments are recorded at fair value
on the balance sheets, with changes in the fair value of
non-designated hedges recognized in net earnings. The amounts
ultimately realized may be materially different than reflected in
the financial statements due to changes in prices of the underlying
items hedged, primarily crude oil and natural gas.
(3) Unrealized foreign exchange gains and losses result
primarily from the translation of US dollar denominated long-term
debt to period-end exchange rates, partially offset by the impact
of cross currency swaps, and are recognized in net earnings.
(4) During the fourth quarter of 2012, the Company repaid US$350
million of 5.45% unsecured notes. During the third quarter of 2011,
the Company repaid US$400 million of 6.70% unsecured notes.
(5) All substantively enacted adjustments in applicable income
tax rates and other legislative changes are applied to underlying
assets and liabilities on the Company's balance sheets in
determining deferred income tax assets and liabilities. The impact
of these tax rate and other legislative changes is recorded in net
earnings during the period the legislation is substantively
enacted. During the third quarter of 2012, the UK government
enacted legislation to restrict the combined corporate and
supplementary income tax rate relief on UK North Sea
decommissioning expenditures to 50%, resulting in an increase in
the Company's deferred income tax liability of $58 million. During
the first quarter of 2011, the UK government enacted legislation to
increase the corporate income tax rate charged on profits from UK
North Sea crude oil and natural gas production from 50% to 62%. The
Company's deferred income tax liability was increased by $104
million with respect to this tax rate change.
Cash Flow from Operations
Three Months Ended Year Ended
------------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings $ 352 $ 360 $ 832 $ 1,892 $ 2,643
Non-cash items:
Depletion,
depreciation
and
amortization 1,213 1,056 998 4,328 3,604
Share-based
compensation (41) 49 207 (214) (102)
Asset
retirement
obligation
accretion 38 38 33 151 130
Unrealized
risk
management
loss (gain) 8 34 58 (42) (128)
Unrealized
foreign
exchange loss
(gain) 254 (136) (117) 129 215
Realized
foreign
exchange gain
on repayment
of US dollar
debt
securities (210) - - (210) (225)
Equity loss
from jointly
controlled
entity 3 1 - 9 -
Deferred
income tax
(recovery)
expense (69) 29 144 (30) 407
Horizon asset
impairment
provision - - - - 396
Insurance
recovery -
property damage - - 3 - (393)
----------------------------------------------------------------------------
Cash flow from
operations $ 1,548 $ 1,431 $ 2,158 $ 6,013 $ 6,547
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
Net earnings for the year ended December 31, 2012 were $1,892
million compared with $2,643 million for the year ended December
31, 2011. Net earnings for the year ended December 31, 2012
included net after-tax income of $274 million compared with $103
million for the year ended December 31, 2011 related to the effects
of share-based compensation, risk management activities,
fluctuations in foreign exchange rates, the impact of a realized
foreign exchange gain on repayment of long-term debt and the impact
of statutory tax rate and other legislative changes on deferred
income tax liabilities. Excluding these items, adjusted net
earnings from operations for the year ended December 31, 2012 were
$1,618 million compared with $2,540 million for the year ended
December 31, 2011.
Net earnings for the fourth quarter of 2012 were $352 million
compared with $832 million for the fourth quarter of 2011 and $360
million for the third quarter of 2012. Net earnings for the fourth
quarter of 2012 included net after-tax expenses of $7 million
compared with $140 million for the fourth quarter of 2011 and net
after-tax income of $7 million for the third quarter of 2012
related to the effects of share-based compensation, risk management
activities, fluctuations in foreign exchange rates, the impact of a
realized foreign exchange gain on repayment of long-term debt and
the impact of statutory tax rate and other legislative changes on
deferred income tax liabilities. Excluding these items, adjusted
net earnings from operations for the fourth quarter of 2012 were
$359 million compared with $972 million for the fourth quarter of
2011 and $353 million for the third quarter of 2012.
The decrease in adjusted net earnings for the year ended
December 31, 2012 from the year ended December 31, 2011 was
primarily due to:
- lower crude oil and NGLs and natural gas netbacks;
- lower realized synthetic crude oil ("SCO") prices;
- higher depletion, depreciation and amortization expense;
and
- higher realized risk management losses;
partially offset by:
- higher crude oil and SCO sales volumes in the North America
and Oil Sands Mining and Upgrading segments.
The decrease in adjusted net earnings for the fourth quarter of
2012 from the fourth quarter of 2011 was primarily due to:
- lower crude oil and NGLs and natural gas netbacks;
- lower realized SCO prices;
- lower natural gas sales volumes;
- lower SCO sales volumes in the Oil Sands Mining and Upgrading
segment;
- higher depletion, depreciation and amortization expense;
and
- the impact of a stronger Canadian dollar;
partially offset by:
- higher crude oil sales volumes in the North America
segment.
The adjusted net earnings for the fourth quarter of 2012 were
comparable with the third quarter of 2012.
The impacts of share-based compensation, risk management
activities and changes in foreign exchange rates are expected to
continue to contribute to quarterly volatility in consolidated net
earnings and are discussed in detail in the relevant sections of
this MD&A.
Cash flow from operations for the year ended December 31, 2012
was $6,013 million compared with $6,547 million for the year ended
December 31, 2011. Cash flow from operations for the fourth quarter
of 2012 was $1,548 million compared with $2,158 million for the
fourth quarter of 2011 and $1,431 million for the third quarter of
2012. The fluctuations in cash flow from operations from the
comparable periods was primarily due to the factors noted above
relating to the fluctuations in adjusted net earnings, excluding
depletion, depreciation and amortization expense, as well as due to
the impact of cash taxes.
Total production before royalties for the year ended December
31, 2012 increased 9% to 654,665 BOE/d from 598,526 BOE/d for the
year ended December 31, 2011. Total production before royalties for
the fourth quarter of 2012 was comparable with the fourth quarter
of 2011 and the third quarter of 2012.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results
for the eight most recently completed quarters:
($ millions, except per common Dec 31 Sep 30 Jun 30 Mar 31
share amounts) 2012 2012 2012 2012
----------------------------------------------------------------------------
Product sales $ 4,059 $ 3,978 $ 4,187 $ 3,971
Net earnings $ 352 $ 360 $ 753 $ 427
Net earnings per common share
- basic $ 0.32 $ 0.33 $ 0.68 $ 0.39
- diluted $ 0.32 $ 0.33 $ 0.68 $ 0.39
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per common Dec 31 Sep 30 Jun 30 Mar 31
share amounts) 2011 2011 2011 2011
----------------------------------------------------------------------------
Product sales $ 4,788 $ 3,690 $ 3,727 $ 3,302
Net earnings $ 832 $ 836 $ 929 $ 46
Net earnings per common share
- basic $ 0.76 $ 0.76 $ 0.85 $ 0.04
- diluted $ 0.76 $ 0.76 $ 0.84 $ 0.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volatility in the quarterly net earnings over the eight most
recently completed quarters was primarily due to:
- Crude oil pricing - The impact of fluctuating demand,
inventory storage levels and geopolitical uncertainties on
worldwide benchmark pricing, the impact of the WCS Heavy
Differential from West Texas Intermediate ("WTI") in North America
and the impact of the differential between WTI and Dated Brent
benchmark pricing in the North Sea and Offshore Africa.
- Natural gas pricing - The impact of fluctuations in both the
demand for natural gas and inventory storage levels, and the impact
of increased shale gas production in the US.
- Crude oil and NGLs sales volumes - Fluctuations in production
due to the cyclic nature of the Company's Primrose thermal
projects, the results from the Pelican Lake water and polymer flood
projects, the record heavy oil drilling program, and the impact of
the suspension and recommencement of production at Horizon. Sales
volumes also reflected fluctuations due to timing of liftings and
maintenance activities in the North Sea and Offshore Africa, and
payout of the Baobab field in May 2011.
- Natural gas sales volumes - Fluctuations in production due to
the Company's strategic decision to reduce natural gas drilling
activity in North America and the allocation of capital to higher
return crude oil projects, as well as natural decline rates,
shut-in natural gas production due to pricing and the impact and
timing of acquisitions.
- Production expense - Fluctuations primarily due to the impact
of the demand for services, fluctuations in product mix, the impact
of seasonal costs that are dependent on weather, production and
cost optimizations in North America, acquisitions of natural gas
producing properties in 2011 that had higher operating costs per
Mcf than the Company's existing properties, and the suspension and
recommencement of production at Horizon.
- Depletion, depreciation and amortization - Fluctuations due to
changes in sales volumes, proved reserves, asset retirement
obligations, finding and development costs associated with crude
oil and natural gas exploration, estimated future costs to develop
the Company's proved undeveloped reserves, and the impact of the
suspension and recommencement of production at Horizon.
- Share-based compensation - Fluctuations due to the
determination of fair market value based on the Black-Scholes
valuation model of the Company's share-based compensation
liability.
- Risk management - Fluctuations due to the recognition of gains
and losses from the mark-to-market and subsequent settlement of the
Company's risk management activities.
- Foreign exchange rates - Changes in the Canadian dollar
relative to the US dollar that impacted the realized price the
Company received for its crude oil and natural gas sales, as sales
prices are based predominately on US dollar denominated benchmarks.
Fluctuations in realized and unrealized foreign exchange gains and
losses are recorded with respect to US dollar denominated debt,
partially offset by the impact of cross currency swap hedges.
- Income tax expense - Fluctuations in income tax expense
include statutory tax rate and other legislative changes
substantively enacted in the various periods.
BUSINESS ENVIRONMENT
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
WTI benchmark price
(US$/bbl) $ 88.20 $ 92.19 $ 94.02 $ 94.19 $ 95.14
Dated Brent benchmark
price (US$/bbl) $ 110.03 $ 109.57 $ 109.29 $ 111.56 $ 111.29
WCS blend
differential from
WTI (US$/bbl) $ 18.15 $ 21.78 $ 10.49 $ 21.05 $ 17.10
WCS blend
differential from
WTI (%) 21% 24% 11% 22% 18%
SCO price (US$/bbl) $ 91.90 $ 90.84 $ 102.95 $ 92.59 $ 103.63
Condensate benchmark
price (US$/bbl) $ 98.13 $ 96.09 $ 108.68 $ 100.92 $ 105.38
NYMEX benchmark price
(US$/MMBtu) $ 3.36 $ 2.82 $ 3.61 $ 2.80 $ 4.07
AECO benchmark price
(C$/GJ) $ 2.89 $ 2.08 $ 3.29 $ 2.28 $ 3.48
US/Canadian dollar
average exchange
rate (US$) $ 1.0088 $ 1.0047 $ 0.9773 $ 1.0004 $ 1.0111
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commodity Prices
Crude oil sales contracts in the North America segment are
typically based on WTI benchmark pricing. WTI averaged US$94.19 per
bbl for the year ended December 31, 2012, a decrease of 1% from
US$95.14 per bbl for the year ended December 31, 2011. WTI averaged
US$88.20 per bbl for the fourth quarter of 2012, a decrease of 6%
from US$94.02 per bbl for the fourth quarter of 2011, and a
decrease of 4% from US$92.19 per bbl for the third quarter of 2012.
WTI pricing was reflective of the political instability in the
Middle East, the declining optimism in the United States economy
related to the fiscal cliff, the European debt crisis, and lower
than expected growth in Asian demand.
Crude oil sales contracts for the Company's North Sea and
Offshore Africa segments are typically based on Dated Brent
("Brent") pricing, which is representative of international markets
and overall world supply and demand. Brent averaged US$111.56 per
bbl for the year ended December 31, 2012 and was comparable with
the year ended December 31, 2011. Brent averaged US$110.03 per bbl
for the fourth quarter of 2012 and was comparable with the
comparative periods. The higher Brent pricing relative to WTI was
due to logistical constraints and high inventory levels of crude
oil at Cushing.
The WCS Heavy Differential averaged 22% for the year ended
December 31, 2012 compared with 18% for the year ended December 31,
2011. The WCS Heavy Differential averaged 21% for the fourth
quarter of 2012, compared with 11% in the fourth quarter of 2011,
and 24% for the third quarter of 2012. The WCS Heavy Differential
for October and November 2012 narrowed, averaging 11% and 16%
respectively. The WCS Heavy Differential widened in December 2012
to average 34% as a result of unplanned Enbridge pipeline capacity
limitations and refinery plans to lower crude inventories for year
end. The impact of higher WCS Heavy Differentials in January and
February 2013 of 35% and 39% respectively were partially offset by
higher overall WTI benchmark pricing. The WCS Heavy Differential
narrowed in March 2013 to average approximately 29%.
The Company uses condensate as a blending diluent for heavy
crude oil pipeline shipments. During the fourth quarter of 2012,
condensate prices continued to trade at a premium to WTI, similar
to prior periods, reflecting normal seasonality.
The Company anticipates continued volatility in crude oil
pricing benchmarks due to supply and demand factors, geopolitical
events, and the timing and extent of the economic recovery. The WCS
Heavy Differential is expected to continue to reflect seasonal
demand fluctuations, changes in transportation logistics, and
refinery utilization and shutdowns.
NYMEX natural gas prices averaged US$2.80 per MMBtu for the year
ended December 31, 2012, a decrease of 31% from US$4.07 per MMBtu
for the year ended December 31, 2011. NYMEX natural gas prices
averaged US$3.36 per MMBtu for the fourth quarter of 2012, a
decrease of 7% from US$3.61 per MMBtu for the fourth quarter of
2011, and an increase of 19% from US$2.82 per MMBtu for the third
quarter of 2012.
AECO natural gas prices for the year ended December 31, 2012
averaged $2.28 per GJ, a decrease of 34% from $3.48 per GJ for the
year ended December 31, 2011. AECO natural gas prices for the
fourth quarter of 2012 averaged $2.89 per GJ, a decrease of 12%
from $3.29 per GJ for the fourth quarter of 2011, and an increase
of 39% from $2.08 per GJ for the third quarter of 2012.
During the fourth quarter of 2012, natural gas prices continued
to recover from the low pricing levels in 2012. While Canadian
production has declined in response to low prices, US production
has held steady during 2012. Natural gas pricing continues to be
volatile as the market still requires a shift to higher utilization
of gas fired electric generation to offset the strong North America
supply position.
The Company continues to focus on its crude oil marketing
strategy including a blending strategy that expands markets within
current pipeline infrastructure, supporting pipeline projects that
provide crude oil transportation to new markets, and supporting
incremental heavy crude oil conversion capacity. During the fourth
quarter of 2012, the Company entered into a 20 year transportation
agreement to ship 75,000 bbl/d of crude oil on the proposed Kinder
Morgan Trans Mountain Expansion from Edmonton, Alberta to
Vancouver, British Columbia. The regulatory approval process will
begin in 2013 with a planned in-service date in 2017.
DAILY PRODUCTION, before royalties
Three Months Ended Year Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America -
Exploration and
Production 351,983 332,895 291,839 326,829 295,618
North America -Oil Sands
Mining and Upgrading 83,079 99,205 102,952 86,077 40,434
North Sea 19,140 19,502 26,769 19,824 29,992
Offshore Africa 15,762 17,566 22,726 18,648 23,009
----------------------------------------------------------------------------
469,964 469,168 444,286 451,378 389,053
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,113 1,169 1,255 1,198 1,231
North Sea 1 2 6 2 7
Offshore Africa 20 20 19 20 19
----------------------------------------------------------------------------
1,134 1,191 1,280 1,220 1,257
----------------------------------------------------------------------------
Total barrels of oil
equivalent (BOE/d) 658,973 667,616 657,599 654,665 598,526
----------------------------------------------------------------------------
Product mix
Light and medium crude oil
and NGLs 15% 15% 17% 16% 18%
Pelican Lake heavy crude
oil 5% 6% 6% 6% 6%
Primary heavy crude oil 20% 19% 17% 19% 18%
Bitumen (thermal oil) 18% 15% 12% 15% 16%
Synthetic crude oil 13% 15% 16% 13% 7%
Natural gas 29% 30% 32% 31% 35%
----------------------------------------------------------------------------
Percentage of product
sales (1)(excluding
midstream revenue)
Crude oil and NGLs 89% 92% 90% 91% 86%
Natural gas 11% 8% 10% 9% 14%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation and blending costs and excluding risk
management activities.
DAILY PRODUCTION, net of royalties
Three Months Ended Year Ended
---------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America - Exploration and
Production 305,577 261,655 230,522 273,374 240,006
North America - Oil Sands
Mining and Upgrading 79,691 95,704 98,287 82,171 38,721
North Sea 19,096 19,441 26,714 19,772 29,919
Offshore Africa 10,358 11,662 19,331 13,628 20,532
----------------------------------------------------------------------------
414,722 388,462 374,854 388,945 329,178
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,047 1,159 1,211 1,171 1,186
North Sea 1 2 6 2 7
Offshore Africa 16 16 16 17 16
----------------------------------------------------------------------------
1,064 1,177 1,233 1,190 1,209
----------------------------------------------------------------------------
Total barrels of oil equivalent
(BOE/d) 592,080 584,577 580,242 587,246 530,576
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's business approach is to maintain large project
inventories and production diversification among each of the
commodities it produces; namely natural gas, light and medium crude
oil and NGLs, Pelican Lake heavy crude oil, primary heavy crude
oil, bitumen (thermal oil) and SCO.
Crude oil and NGLs production for the year ended December 31,
2012 increased 16% to 451,378 bbl/d from 389,053 bbl/d for the year
ended December 31, 2011. Crude oil and NGLs production for the
fourth quarter of 2012 increased 6% to 469,964 bbl/d from 444,286
bbl/d for the fourth quarter of 2011 and was comparable with the
third quarter of 2012. The increase in production from the
comparable periods in 2011 was primarily related to the impact of a
strong heavy crude oil drilling program and the cyclic nature of
the Company's thermal operations. Crude oil and NGLs production in
the fourth quarter of 2012 was within the Company's previously
issued guidance of 467,000 to 495,000 bbl/d.
Natural gas production for the year ended December 31, 2012
decreased 3% to 1,220 MMcf/d from 1,257 MMcf/d for the year ended
December 31, 2011. Natural gas production for the fourth quarter of
2012 decreased 11% to 1,134 MMcf/d from 1,280 MMcf/d for the fourth
quarter of 2011 and decreased 5% from 1,191 MMcf/d for the third
quarter of 2012. The decrease in natural gas production for the
three months and year ended December 31, 2012 from the comparable
periods was primarily a result of a strategic reduction of natural
gas drilling as the Company allocated capital to higher return
crude oil projects, as well as expected production declines. During
the fourth quarter of 2012, certain gas processing contract
arrangements were ended to provide greater flexibility of cost
control, resulting in the shut in of additional natural gas
production. As a result of the shut-in natural gas, natural gas
production in the fourth quarter of 2012 was slightly below the
Company's previously issued guidance of 1,145 to 1,165 MMcf/d.
For 2013, annual production guidance is targeted to average
between 482,000 and 513,000 bbl/d of crude oil and NGLs and between
1,085 and 1,145 MMcf/d of natural gas. First quarter 2013
production guidance is targeted to average between 471,000 and
495,000 bbl/d of crude oil and NGLs and between 1,130 and 1,150
MMcf/d of natural gas.
North America - Exploration and Production
North America crude oil and NGLs production for the year ended
December 31, 2012 increased 11% to average 326,829 bbl/d from
295,618 bbl/d for the year ended December 31, 2011. For the fourth
quarter of 2012, crude oil and NGLs production increased 21% to
average 351,983 bbl/d compared with 291,839 bbl/d for the fourth
quarter of 2011 and increased 6% from 332,895 bbl/d in the third
quarter of 2012. Increases in crude oil and NGLs production from
comparable periods were primarily due to the impact of a strong
heavy crude oil drilling program and the cyclic nature of the
Company's thermal operations. Fourth quarter 2012 production of
crude oil and NGLs was within the Company's previously issued
guidance of 350,000 bbl/d to 365,000 bbl/d. First quarter 2013
production guidance is targeted to average between 335,000 and
349,000 bbl/d for crude oil and NGLs.
Natural gas production for the year ended December 31, 2012
decreased 3% to 1,198 MMcf/d compared with 1,231 MMcf/d for the
year ended December 31, 2011. Natural gas production decreased 11%
to 1,113 MMcf/d for the fourth quarter of 2012 compared with 1,255
MMcf/d in the fourth quarter of 2011 and decreased 5% from 1,169
MMcf/d in the third quarter of 2012. The decrease in natural gas
production for the three months and year ended December 31, 2012
from the comparable periods was primarily a result of a strategic
reduction of natural gas drilling as the Company allocated capital
to higher return crude oil projects, as well as expected production
declines. During the fourth quarter of 2012, certain gas processing
contract arrangements were ended to provide greater flexibility of
cost control, resulting in the shut in of additional natural gas
production.
North America - Oil Sands Mining and Upgrading
Production averaged 86,077 bbl/d for the year ended December 31,
2012 compared with 40,434 bbl/d for the year ended December 31,
2011. For the fourth quarter of 2012, SCO production averaged
83,079 bbl/d compared with 102,952 bbl/d for the fourth quarter of
2011 and 99,205 bbl/d for the third quarter of 2012. Production for
the year ended December 31, 2012 increased from the comparable
period in 2011 as a result of the suspension of production during a
portion of 2011. Fourth quarter production in 2012 decreased from
the fourth quarter of 2011 and the third quarter of 2012 as the
Company completed a 12 day planned maintenance outage in October
2012 as well as additional maintenance in the ore preparation
plants in December 2012. Production of SCO was slightly below the
Company's previously issued guidance of 85,000 to 92,000 bbl/d for
the fourth quarter of 2012. First quarter 2013 production guidance
is targeted to average between 105,000 and 111,000 bbl/d.
North Sea
North Sea crude oil production for the year ended December 31,
2012 decreased 34% to 19,824 bbl/d from 29,992 bbl/d for the year
ended December 31, 2011. For the fourth quarter of 2012, North Sea
crude oil production decreased 28% to 19,140 bbl/d from 26,769
bbl/d for the fourth quarter of 2011, and decreased 2% from 19,502
bbl/d in the third quarter of 2012. The decrease in production
volumes for the three months and year ended December 31, 2012 from
the comparable periods was primarily due to temporary shut ins of
the third-party operated pipeline to Sullom Voe, which caused all
Ninian and associated fields to be shut in for a portion of the
third and fourth quarters of 2012, the suspension of production at
Banff/Kyle, and natural field declines. In addition, the Company
accelerated its fourth quarter 2012 planned turnaround activity to
mitigate the impact of the pipeline outage.
In December 2011, the Banff Floating Production, Storage and
Offloading Vessel ("FPSO") and subsea infrastructure suffered storm
damage. Operations at Banff/Kyle, with combined net production of
approximately 3,500 bbl/d, were suspended. The FPSO and associated
floating storage unit have subsequently been removed from the field
and the FPSO is currently in dry dock for assessment of damages and
repair timeframe. The extent of the property damage, including
associated costs, is not expected to be significant.
Offshore Africa
Offshore Africa crude oil production decreased 19% to 18,648
bbl/d for the year ended December 31, 2012 from 23,009 bbl/d for
the year ended December 31, 2011. Fourth quarter 2012 crude oil
production averaged 15,762 bbl/d, decreasing 31% from 22,726 bbl/d
for the fourth quarter of 2011 and decreasing 10% from 17,566 bbl/d
in the third quarter of 2012. The decrease in production volumes
for the three months and year ended December 31, 2012 from the
comparable periods was due to natural field declines, planned
turnaround activity at Espoir, and the shut in of approximately
1,500 bbl/d of production at the Olowi field, Gabon. The Company
currently has a vessel on-site in Gabon assessing the operability
of the midwater arch.
International Guidance
The Company's North Sea and Offshore Africa fourth quarter 2012
crude oil and NGLs production was within the Company's previously
issued guidance of 32,000 to 38,000 bbl/d. First quarter 2013
production guidance is targeted to average between 31,000 and
35,000 bbl/d of crude oil.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when
title transfers to the customer and delivery has taken place.
Revenue has not been recognized on crude oil volumes that were
stored in various tanks, pipelines, or floating production, storage
and offloading vessels, as follows:
------------------------------
Dec 31 Sep 30 Dec 31
(bbl) 2012 2012 2011
----------------------------------------------------------------------------
North America - Exploration and Production 643,758 656,340 557,475
North America - Oil Sands Mining and Upgrading
(SCO) 993,627 888,442 1,021,236
North Sea 77,018 150,269 286,633
Offshore Africa 1,036,509 1,058,992 527,312
----------------------------------------------------------------------------
2,750,912 2,754,043 2,392,656
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
Sales price (2) $ 64.23 $ 67.59 $ 85.28 $ 70.24 $ 77.46
Royalties 8.59 12.08 15.53 10.67 12.30
Production expense 15.32 15.79 16.85 16.11 15.75
----------------------------------------------------------------------------
Netback $ 40.32 $ 39.72 $ 52.90 $ 43.46 $ 49.41
----------------------------------------------------------------------------
Natural gas ($/Mcf)
(1)
Sales price (2) $ 3.16 $ 2.28 $ 3.50 $ 2.44 $ 3.73
Royalties 0.21 0.05 0.18 0.09 0.18
Production expense 1.43 1.30 1.15 1.31 1.15
----------------------------------------------------------------------------
Netback $ 1.52 $ 0.93 $ 2.17 $ 1.04 $ 2.40
----------------------------------------------------------------------------
Barrels of oil
equivalent ($/BOE)
(1)
Sales price (2) $ 49.83 $ 49.08 $ 61.21 $ 50.81 $ 57.16
Royalties 6.22 7.94 10.14 7.07 8.12
Production expense 13.11 12.97 13.12 13.14 12.42
----------------------------------------------------------------------------
Netback $ 30.50 $ 28.17 $ 37.95 $ 30.60 $ 36.62
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
(2) Net of transportation and blending costs and excluding risk
management activities.
PRODUCT PRICES - EXPLORATION AND PRODUCTION
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)(2)
North America $ 60.17 $ 63.73 $ 81.02 $ 65.54 $ 72.17
North Sea $ 108.82 $ 106.68 $ 109.71 $ 110.75 $ 108.56
Offshore Africa $ 97.97 $ 112.59 $ 102.74 $ 111.18 $ 105.53
Company average $ 64.23 $ 67.59 $ 85.28 $ 70.24 $ 77.46
Natural gas ($/Mcf)
(1)(2)
North America $ 3.03 $ 2.15 $ 3.36 $ 2.31 $ 3.64
North Sea $ 2.67 $ 3.65 $ 4.17 $ 3.70 $ 4.07
Offshore Africa $ 10.25 $ 9.95 $ 12.79 $ 10.17 $ 9.56
Company average $ 3.16 $ 2.28 $ 3.50 $ 2.44 $ 3.73
Company average
($/BOE) (1)(2) $ 49.83 $ 49.08 $ 61.21 $ 50.81 $ 57.16
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
(2) Net of transportation and blending costs and excluding risk
management activities.
North America
North America realized crude oil prices decreased 9% to average
$65.54 per bbl for the year ended December 31, 2012 from $72.17 per
bbl for the year ended December 31, 2011. North America realized
crude oil prices averaged $60.17 per bbl for the fourth quarter of
2012, a decrease of 26% compared with $81.02 per bbl for the fourth
quarter of 2011 and a decrease of 6% compared with $63.73 per bbl
for the third quarter of 2012. The decrease in prices for the three
months and year ended December 31, 2012 from the comparable periods
in 2011 was primarily a result of the lower WTI benchmark pricing,
the widening of the WCS Heavy Differential and the fluctuations in
the Canadian dollar relative to the US dollar. The decrease in
prices for the fourth quarter of 2012 from the third quarter of
2012 was primarily due to the lower WTI benchmark pricing,
partially offset by the narrowing of the WCS Heavy Differential.
The Company continues to focus on its crude oil blending marketing
strategy and in the fourth quarter of 2012 contributed
approximately 165,000 bbl/d of heavy crude oil blends to the WCS
stream.
North America realized natural gas prices decreased 37% to
average $2.31 per Mcf for the year ended December 31, 2012 from
$3.64 per Mcf for the year ended December 31, 2011. North America
realized natural gas prices decreased 10% to average $3.03 per Mcf
for the fourth quarter of 2012 compared with $3.36 per Mcf in the
fourth quarter of 2011, and increased 41% compared with $2.15 per
Mcf for the third quarter of 2012. The decrease in natural gas
prices for the three months and year ended December 31, 2012 from
the comparable periods in 2011 was primarily due to lower NYMEX and
AECO benchmark pricing related to the impact of strong supply from
US shale projects. The increase in natural gas prices for the
fourth quarter of 2012 from the third quarter of 2012 was primarily
due to higher NYMEX and AECO benchmark pricing related to a shift
to higher utilization of gas fired electric generation and
seasonality.
Comparisons of the prices received in North America Exploration
and Production by product type were as follows:
---------------------------------
Dec 31 Sep 30 Dec 31
(Quarterly Average) 2012 2012 2011
----------------------------------------------------------------------------
Wellhead Price(1) (2)
Light and medium crude oil and NGLs ($/bbl) $ 68.67 $ 67.33 $ 86.05
Pelican Lake heavy crude oil ($/bbl) $ 61.32 $ 63.03 $ 81.64
Primary heavy crude oil ($/bbl) $ 59.42 $ 61.54 $ 79.91
Bitumen (thermal oil) ($/bbl) $ 56.14 $ 64.56 $ 78.38
Natural gas ($/Mcf) $ 3.03 $ 2.15 $ 3.36
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
(2) Net of transportation and blending costs and excluding risk
management activities.
North Sea
North Sea realized crude oil prices increased 2% to average
$110.75 per bbl for the year ended December 31, 2012 from $108.56
per bbl for the year ended December 31, 2011. Realized crude oil
prices averaged $108.82 per bbl for the fourth quarter of 2012, a
decrease of 1% from $109.71 per bbl for the fourth quarter of 2011,
and an increase of 2% from $106.68 per bbl for the third quarter of
2012. The fluctuations in realized crude oil prices in the North
Sea from the comparable periods in 2011 were primarily the result
of fluctuations in the Brent benchmark pricing and the Canadian
dollar, and the timing of liftings.
Offshore Africa
Offshore Africa realized crude oil prices increased 5% to
average $111.18 per bbl for the year ended December 31, 2012 from
$105.53 per bbl for the year ended December 31, 2011. Realized
crude oil prices decreased 5% to average $97.97 per bbl for the
fourth quarter of 2012 from $102.74 per bbl for the fourth quarter
of 2011, and decreased 13% from $112.59 per bbl for the third
quarter of 2012. The fluctuations in realized crude oil prices in
Offshore Africa from the comparable periods were primarily the
result of the fluctuations in the Brent benchmark pricing and the
Canadian dollar, and the timing of liftings.
ROYALTIES - EXPLORATION AND PRODUCTION
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
North America $ 7.93 $ 11.65 $ 17.10 $ 10.33 $ 13.51
North Sea $ 0.25 $ 0.33 $ 0.23 $ 0.29 $ 0.26
Offshore Africa $ 33.59 $ 37.84 $ 15.35 $ 29.46 $ 12.47
Company average $ 8.59 $ 12.08 $ 15.53 $ 10.67 $ 12.30
Natural gas ($/Mcf)
(1)
North America $ 0.18 $ 0.02 $ 0.15 $ 0.06 $ 0.16
Offshore Africa $ 1.74 $ 1.89 $ 2.33 $ 1.77 $ 1.59
Company average $ 0.21 $ 0.05 $ 0.18 $ 0.09 $ 0.18
Company average
($/BOE) (1) $ 6.22 $ 7.94 $ 10.14 $ 7.07 $ 8.12
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
North America
North America crude oil and natural gas royalties for the year
ended December 31, 2012 compared with the year ended December 31,
2011 reflected benchmark commodity prices and the widening of the
WCS Heavy Differential.
Crude oil and NGLs royalties averaged approximately 16% of
product sales in 2012 compared with 19% in 2011. Crude oil and NGLs
royalties averaged approximately 13% of product sales for the
fourth quarter of 2012 compared with 21% for the fourth quarter of
2011 and 18% for the third quarter of 2012. The decrease in
royalties from the comparable periods was the result of lower WTI
benchmark pricing and changes in the WCS Heavy Differential. Crude
oil and NGLs royalties per bbl are anticipated to average 16% to
18% of product sales for 2013.
Natural gas royalties averaged approximately 3% of product sales
in 2012 compared with 4% in 2011. Natural gas royalties averaged
approximately 6% of product sales for the fourth quarter of 2012
compared with 4% for the fourth quarter of 2011 and 1% for the
third quarter of 2012. The fluctuations in natural gas royalty
rates from the comparable periods were primarily the result of
fluctuations in realized natural gas prices, together with gas cost
allowance adjustments. Natural gas royalties are anticipated to
average 4% to 6% of product sales for 2013.
Offshore Africa
Under the terms of the various Production Sharing Contracts,
royalty rates fluctuate based on realized commodity pricing,
capital and operating costs, the status of payouts, and the timing
of liftings from each field.
Royalty rates as a percentage of product sales averaged
approximately 26% in 2012 compared with 17% in 2011. Royalty rates
as a percentage of product sales averaged approximately 32% for the
fourth and third quarters of 2012 compared with 18% for the fourth
quarter of 2011. The increase in royalty rates from the comparable
periods in 2011 was due to higher crude oil prices during the year,
adjustments to royalties on liftings, and the payout of the Baobab
field in May 2011.
Offshore Africa royalty rates are anticipated to average 9% to
11% of product sales for 2013.
PRODUCTION EXPENSE - EXPLORATION AND PRODUCTION
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
North America $ 12.79 $ 12.52 $ 14.32 $ 13.40 $ 13.21
North Sea $ 54.41 $ 60.94 $ 36.45 $ 53.53 $ 37.06
Offshore Africa $ 22.14 $ 38.34 $ 22.16 $ 23.11 $ 20.72
Company average $ 15.32 $ 15.79 $ 16.85 $ 16.11 $ 15.75
Natural gas ($/Mcf)
(1)
North America $ 1.40 $ 1.28 $ 1.12 $ 1.28 $ 1.12
North Sea $ 3.58 $ 3.44 $ 3.51 $ 3.75 $ 2.83
Offshore Africa $ 3.19 $ 2.37 $ 2.52 $ 2.27 $ 2.03
Company average $ 1.43 $ 1.30 $ 1.15 $ 1.31 $ 1.15
Company average
($/BOE) (1) $ 13.11 $ 12.97 $ 13.12 $ 13.14 $ 12.42
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
North America
North America crude oil and NGLs production expense for the year
ended December 31, 2012 averaged $13.40 per bbl and was comparable
with the year ended December 31, 2011. North America crude oil and
NGLs production expense for the fourth quarter of 2012 decreased
11% to $12.79 per bbl from $14.32 per bbl for the fourth quarter of
2011 and increased 2% from $12.52 per bbl for the third quarter of
2012. The increase in production expense for the three months ended
December 31, 2012 from the third quarter of 2012 was primarily the
result of higher servicing cost pressures in Heavy Oil. North
America 2012 crude oil and NGLs production expense was slightly
higher than the Company's previously issued guidance of $12.75 to
$13.25 per bbl, and is anticipated to average $12.00 to $14.00 per
bbl for 2013.
North America natural gas production expense for the year ended
December 31, 2012 increased 14% to $1.28 per Mcf from $1.12 per Mcf
for the year ended December 31, 2011. North America natural gas
production expense for the fourth quarter of 2012 increased 25% to
$1.40 per Mcf from $1.12 per Mcf for the fourth quarter of 2011 and
increased 9% from $1.28 per Mcf for the third quarter of 2012.
Natural gas production expense for the three months and year ended
December 31, 2012 increased from the comparable periods due to the
impact of shut-in production and lower production volumes related
to the curtailment of capital expenditures related to natural gas
activity. During the fourth quarter of 2012, certain gas processing
contract arrangements were ended to provide greater flexibility of
cost control, resulting in the shut in of additional natural gas
production. North America 2012 natural gas production expense was
slightly higher than the Company's previously issued guidance of
$1.22 to $1.26 per Mcf, and is anticipated to average $1.30 to
$1.40 per Mcf for 2013.
North Sea
North Sea crude oil production expense for the year ended
December 31, 2012 increased 44% to $53.53 per bbl from $37.06 per
bbl for the year ended December 31, 2011. North Sea crude oil
production expense for the fourth quarter of 2012 decreased 11% to
$54.41 per bbl from $60.94 per bbl for the third quarter of 2012
and increased 49% from $36.45 per bbl for the fourth quarter of
2011. Production expense decreased for the fourth quarter of 2012
from the third quarter of 2012 due to a reduced level of
maintenance activity. Production expense increased on a per barrel
basis for the three months and year ended December 31, 2012 from
the comparable periods in 2011 due to the impact of production
declines on relatively fixed costs, temporary shut ins of the
third-party operated pipeline to Sullom Voe, and higher maintenance
costs related to turnaround activity. North Sea 2012 crude oil
production expense was slightly higher than the Company's
previously issued guidance of $52.00 to $53.00 per bbl, and is
anticipated to average $62.00 to $66.00 per bbl for 2013 due to
natural declines on a relatively fixed cost structure.
Offshore Africa
Offshore Africa crude oil production expense increased 12% to
$23.11 per bbl from $20.72 per bbl for the year ended December 31,
2012. Offshore Africa crude oil production expense for the fourth
quarter of 2012 averaged $22.14 per bbl, comparable with the fourth
quarter of 2011, and decreased 42% from $38.34 per bbl for the
third quarter of 2012. Production expense for the three months and
year ended December 31, 2012 fluctuated from the comparable periods
as a result of the timing of liftings from various fields, which
have different cost structures. Offshore Africa 2012 crude oil
production expense was below the Company's previously issued
guidance of $24.50 to $25.50 per bbl, and is anticipated to average
$33.50 to $37.50 per bbl for 2013 due to timing of liftings from
various fields.
DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND
PRODUCTION
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense ($ millions) $ 1,097 $ 931 $ 863 $ 3,874 $ 3,331
$/BOE (1) $ 20.66 $ 18.00 $ 16.51 $ 18.65 $ 16.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
Depletion, depreciation and amortization expense increased for
the three months and year ended December 30, 2012 compared with
2011 due to higher sales volumes in North America associated with
heavy oil drilling and higher overall future development costs. The
increase in depletion, depreciation and amortization expense from
the third quarter of 2012 was primarily due to higher sales volumes
in North America.
ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND
PRODUCTION
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense ($ millions) $ 30 $ 30 $ 28 $ 119 $ 110
$/BOE (1) $ 0.56 $ 0.59 $ 0.54 $ 0.57 $ 0.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
Asset retirement obligation accretion expense represents the
increase in the carrying amount of the asset retirement obligation
due to the passage of time.
OPERATING HIGHLIGHTS - OIL SANDS MINING AND UPGRADING
OPERATIONS UPDATE
During October 2012, the Company completed a planned 12 day
maintenance outage, as well as additional maintenance in the ore
preparation plants during December 2012. These maintenance
activities resulted in production of 83,079 bbl/d of SCO in the
fourth quarter of 2012, which was slightly below the Company's
previously issued guidance of 85,000 to 92,000 bbl/d of SCO. The
Company continues to focus on efficient and effective operations at
Horizon and place emphasis on safe, steady, reliable operations,
resulting in January and February 2013 production of approximately
113,000 bbl/d and 107,000 bbl/d respectively. In the second quarter
of 2013, Horizon will enter into a 24 day planned maintenance
turnaround, resulting in a plant-wide shut down. The impact of the
turnaround has been reflected in the Company's 2013 production,
cash production cost and capital expenditure guidance.
PRODUCT PRICES AND ROYALTIES - OIL SANDS MINING AND
UPGRADING
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($/bbl) (1) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
SCO sales price (2) $ 87.34 $ 87.40 $ 103.16 $ 88.91 $ 99.74
Bitumen value for
royalty purposes (3) $ 58.12 $ 57.40 $ 69.91 $ 59.93 $ 61.86
Bitumen royalties (4) $ 3.80 $ 3.45 $ 4.21 $ 4.34 $ 3.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes excluding the period during suspension of production.
(2) Net of transportation.
(3) Calculated as the simple quarterly average of the bitumen
valuation methodology price.
(4) Calculated based on actual bitumen royalties expensed during
the period; divided by the corresponding SCO sales volumes.
Realized SCO sales prices averaged $88.91 per bbl for the year
ended December 31, 2012, a decrease of 11% compared with $99.74 per
bbl for the year ended December 31, 2011. Realized SCO sales prices
averaged $87.34 per bbl for the fourth quarter of 2012, a decrease
of 15% compared with $103.16 per bbl for the fourth quarter of 2011
and were comparable with the third quarter of 2012, reflecting
benchmark pricing and prevailing differentials.
PRODUCTION COSTS - OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and
Upgrading production costs disclosed in the Company's unaudited
interim consolidated financial statements.
Three Months Ended Year Ended
---------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Cash production
costs $ 372 $ 398 $ 344 $ 1,504 $ 1,127
Less: costs
incurred during
the period of
suspension of
production - - - (154) (581)
----------------------------------------------------------------------------
Adjusted cash
production costs $ 372 $ 398 $ 344 $ 1,350 $ 546
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Adjusted cash
production costs,
excluding natural
gas costs $ 342 $ 373 $ 316 $ 1,254 $ 502
Adjusted natural
gas costs 30 25 28 96 44
----------------------------------------------------------------------------
Adjusted cash
production costs $ 372 $ 398 $ 344 $ 1,350 $ 546
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($/bbl) (1) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Adjusted cash
production costs,
excluding natural
gas costs $ 45.31 $ 40.03 $ 33.11 $ 39.79 $ 33.68
Adjusted natural gas
costs 3.96 2.66 2.93 3.04 2.96
----------------------------------------------------------------------------
Adjusted cash
production costs $ 49.27 $ 42.69 $ 36.04 $ 42.83 $ 36.64
----------------------------------------------------------------------------
Sales (bbl/d) 81,936 101,263 103,710 86,153 40,847
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes excluding the period during suspension of production.
Adjusted cash production costs averaged $42.83 per bbl for the
year ended December 31, 2012, an increase of 17% compared with
$36.64 per bbl for the year ended December 31, 2011. Adjusted cash
production costs for the fourth quarter of 2012 averaged $49.27 per
bbl, an increase of 37% compared with $36.04 per bbl for the fourth
quarter of 2011 and an increase of 15% compared with $42.69 per bbl
for the third quarter of 2012, primarily due to the impact of lower
production volumes in the period. Cash production costs are
anticipated to average $38.00 to $41.00 per bbl for 2013.
DEPLETION, DEPRECIATION AND AMORTIZATION - OIL SANDS MINING AND
UPGRADING
Three Months Ended Year Ended
---------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Depletion,
depreciation and
amortization $ 114 $ 124 $ 133 $ 447 $ 266
Less: depreciation
incurred during
the period of
suspension of
production - - - (6) (64)
----------------------------------------------------------------------------
Adjusted depletion,
depreciation and
amortization $ 114 $ 124 $ 133 $ 441 $ 202
----------------------------------------------------------------------------
$/bbl (1) $ 15.12 $ 13.31 $ 13.91 $ 13.99 $ 13.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes excluding the period during suspension of production.
Depletion, depreciation and amortization expense reflects the
impact of fluctuations in sales volumes.
ASSET RETIREMENT OBLIGATION ACCRETION - OIL SANDS MINING AND
UPGRADING
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense $ 8 $ 8 $ 5 $ 32 $ 20
$/bbl (1) $ 1.06 $ 0.85 $ 0.52 $ 1.01 $ 1.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
Asset retirement obligation accretion expense represents the
increase in the carrying amount of the asset retirement obligation
due to the passage of time.
MIDSTREAM
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Revenue $ 26 $ 24 $ 22 $ 93 $ 88
Production expense 8 7 7 29 26
----------------------------------------------------------------------------
Midstream cash flow 18 17 15 64 62
Depreciation 2 1 2 7 7
Equity loss from
jointly controlled
entity 3 1 - 9 -
----------------------------------------------------------------------------
Segment earnings
before taxes $ 13 $ 15 $ 13 $ 48 $ 55
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream operating results were consistent with the comparable
periods.
In the first quarter of 2011, the Company announced that it had
entered into a partnership agreement with North West Upgrading Inc.
to move forward with detailed engineering regarding the
construction and operation of a bitumen upgrader and refinery ("the
Project") near Redwater, Alberta. In addition, the partnership has
entered into processing agreements that target to process bitumen
for the Company and the Alberta Petroleum Marketing Commission
("APMC"), an agent of the Government of Alberta, under a 30 year
fee-for-service tolling agreement under the Bitumen Royalty In Kind
initiative. In the fourth quarter of 2012, the Project was
sanctioned by the Board of Directors of each partner of the North
West Redwater Partnership ("Redwater"), and the associated target
toll amounts were accepted by Redwater, the Company and the
APMC.
ADMINISTRATION EXPENSE
Three Months Ended Year Ended
-------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense $ 64 $ 64 $ 47 $ 270 $ 235
$/BOE (1) $ 1.07 $ 1.05 $ 0.76 $ 1.13 $ 1.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
Administration expense for the three months and year ended
December 31, 2012 increased from the comparable periods in 2011
primarily due to higher staffing related costs and general
corporate costs.
SHARE-BASED COMPENSATION
Three Months Ended Year Ended
----------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
(Recovery) expense $ (41) $ 49 $ 207 $ (214) $ (102)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's stock option plan provides current employees with
the right to receive common shares or a direct cash payment in
exchange for stock options surrendered.
The Company recorded a $214 million share-based compensation
recovery for the year ended December 31, 2012, primarily as a
result of remeasurement of the fair value of outstanding stock
options at the end of the period related to a decrease in the
Company's share price, partially offset by normal course graded
vesting of stock options granted in prior periods and the impact of
vested stock options exercised or surrendered during the period.
For the year ended December 31, 2012, a $12 million recovery was
recognized in respect of capitalized share-based compensation to
Oil Sands Mining and Upgrading (December 31, 2011 - $nil).
For the year ended December 31, 2012, the Company paid $7
million for stock options surrendered for cash settlement (December
31, 2011 - $14 million).
INTEREST AND OTHER FINANCING COSTS
Three Months Ended Year Ended
------------------------------------------------------------
($ millions,
except per BOE Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
amounts) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense, gross $ 115 $ 119 $ 102 $ 462 $ 432
Less:
capitalized
interest 32 27 19 98 59
----------------------------------------------------------------------------
Expense, net $ 83 $ 92 $ 83 $ 364 $ 373
$/BOE (1) $ 1.37 $ 1.51 $ 1.35 $ 1.52 $ 1.71
Average
effective
interest rate 4.8% 4.9% 4.7% 4.8% 4.7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
Gross interest and other financing costs for the year ended
December 31, 2012 increased from the comparable period in 2011 due
to higher variable interest rates and the impact of a weaker
Canadian dollar on US dollar denominated debt; partially offset by
lower average debt levels. Gross interest and other financing costs
for the fourth quarter of 2012 increased from the comparable period
in 2011 due to higher variable interest rates, partially offset by
lower average debt levels and the impact of a stronger Canadian
dollar on US dollar denominated debt. Gross interest and other
financing costs were comparable with the third quarter of 2012.
Capitalized interest of $98 million for the year ended December 31,
2012 was related to the Horizon Phase 2/3 expansion and the Kirby
Thermal Oil Sands Project ("Kirby Project").
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to
manage its commodity price, foreign currency and interest rate
exposures. These derivative financial instruments are not intended
for trading or speculative purposes.
Three Months Ended Year Ended
------------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and
NGLs financial
instruments $ 19 $ 18 $ 27 $ 65 $ 117
Foreign currency
contracts and
interest rate
swaps (27) 119 (7) 97 (16)
----------------------------------------------------------------------------
Realized (gain)
loss $ (8) $ 137 $ 20 $ 162 $ 101
----------------------------------------------------------------------------
Crude oil and
NGLs financial
instruments $ 29 $ 58 $ 5 $ 3 $ (134)
Foreign currency
contracts and
interest rate
swaps (21) (24) 53 (45) 6
----------------------------------------------------------------------------
Unrealized loss
(gain) $ 8 $ 34 $ 58 $ (42) $ (128)
----------------------------------------------------------------------------
Net loss (gain) $ - $ 171 $ 78 $ 120 $ (27)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Complete details related to outstanding derivative financial
instruments at December 31, 2012 are disclosed in note 13 to the
Company's unaudited interim consolidated financial statements.
The Company recorded a net unrealized gain of $42 million ($37
million after-tax) on its risk management activities for the year
ended December 31, 2012, including an unrealized loss of $8 million
($4 million after-tax) for the fourth quarter of 2012 (September
30, 2012 - unrealized loss of $34 million; $22 million after-tax;
December 31, 2011 - unrealized loss of $58 million; $50 million
after-tax).
FOREIGN EXCHANGE
Three Months Ended Year Ended
------------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net realized
(gain) loss $ (196) $ 21 $ 11 $ (178) $ (214)
Net unrealized
loss (gain) (1) 254 (136) (117) 129 215
----------------------------------------------------------------------------
Net loss (gain) $ 58 $ (115) $ (106) $ (49) $ 1
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross
currency swaps.
The net realized foreign exchange gain for the year ended
December 31, 2012 was primarily due to the repayment of US$350
million of 5.45% unsecured notes and foreign exchange rate
fluctuations on settlement of working capital items denominated in
US dollars or UK pounds sterling. The net unrealized foreign
exchange loss for the year ended December 31, 2012 was primarily
related to the reversal of the life-to-date unrealized foreign
exchange gain on the repayment of US$350 million of 5.45% unsecured
notes; partially offset by the impact of the strengthening of the
Canadian dollar with respect to remaining US dollar debt. The net
unrealized loss (gain) for each of the periods presented included
the impact of cross currency swaps (three months ended December 31,
2012 - unrealized gain of $27 million, September 30, 2012 -
unrealized loss of $85 million, December 31, 2011 - unrealized loss
of $43 million; year ended December 31, 2012 - unrealized loss of
$53 million, December 31, 2011 - unrealized gain of $42 million).
The US/Canadian dollar exchange rate ended the fourth quarter of
2012 at US$1.0051 (September 30, 2012 - US$1.0166; December 31,
2011 - US$0.9833).
INCOME TAXES
Three Months Ended Year Ended
------------------------------------------------------------
($ millions,
except income Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
tax rates) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
North America
(1) $ 68 $ 61 $ 119 $ 366 $ 315
North Sea 29 22 84 115 245
Offshore Africa 56 50 50 206 140
PRT (recovery)
expense - North
Sea 31 (19) 39 44 135
Other taxes 5 - 7 16 25
----------------------------------------------------------------------------
Current income
tax expense 189 114 299 747 860
----------------------------------------------------------------------------
Deferred income (34) 23 157 - 412
tax (recovery)
expense
Deferred PRT
(recovery)
expense - North
Sea (35) 6 (13) (30) (5)
----------------------------------------------------------------------------
Deferred income (69) 29 144 (30) 407
tax (recovery)
expense
----------------------------------------------------------------------------
120 143 443 717 1,267
Income tax rate
and other
legislative
changes - (58) - (58) (104)
----------------------------------------------------------------------------
$ 120 $ 85 $ 443 $ 659 $ 1,163
----------------------------------------------------------------------------
Effective income
tax rate on
adjusted net
earnings from
operations (2) 25.5% 23.8% 30.1% 27.8% 27.7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes North America Exploration and Production,
Midstream, and Oil Sands Mining and Upgrading segments.
(2) Excludes the impact of current and deferred PRT expense and
other current income tax expense.
During the third quarter of 2012, the UK government enacted
legislation to restrict the combined corporate and supplementary
income tax relief on UK North Sea decommissioning expenditures to
50%. As a result of the income tax rate change, the Company's
deferred income tax liability was increased by $58 million.
During the first quarter of 2011, the UK government enacted
legislation to increase the supplementary income tax rate charged
on profits from UK North Sea crude oil and natural gas production,
increasing the combined corporate and supplementary income tax rate
from 50% to 62%. As a result of the income tax rate change, the
Company's deferred income tax liability was increased by $104
million as at March 31, 2011.
During 2011, the Canadian federal government enacted legislation
to implement several taxation changes. These changes include a
requirement that, beginning in 2012, partnership income must be
included in the taxable income of each corporate partner based on
the tax year of the partner, rather than the fiscal year of the
partnership. The legislation includes a five-year transition
provision and has no impact on net earnings.
The Company files income tax returns in the various
jurisdictions in which it operates. These tax returns are subject
to periodic examinations in the normal course by the applicable tax
authorities. The tax returns as prepared may include filing
positions that could be subject to differing interpretations of
applicable tax laws and regulations, which may take several years
to resolve. The Company does not believe the ultimate resolution of
these matters will have a material impact upon the Company's
results of operations, financial position or liquidity.
For 2013, based on budgeted prices and the current availability
of tax pools, the Company expects to incur current income tax
expense of $550 million to $650 million in Canada and $10 million
to $100 million in the North Sea and Offshore Africa.
NET CAPITAL EXPENDITURES (1)
Three Months Ended Year Ended
--------------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Exploration and
Evaluation
Net expenditures $ 10 $ 59 $ 112 $ 309 $ 312
----------------------------------------------------------------------------
Property, Plant and
Equipment
Net property
acquisitions 76 23 396 144 1,012
Well drilling,
completion and
equipping 566 485 585 1,902 1,878
Production and
related facilities 495 533 480 1,978 1,690
Capitalized interest
and other (2) 23 28 26 111 104
----------------------------------------------------------------------------
Net expenditures 1,160 1,069 1,487 4,135 4,684
----------------------------------------------------------------------------
Total Exploration
and Production 1,170 1,128 1,599 4,444 4,996
----------------------------------------------------------------------------
Oil Sands Mining and
Upgrading
Horizon Phases 2/3
construction costs 423 354 150 1,315 481
Sustaining capital 94 41 44 223 170
Turnaround costs 5 11 - 21 79
Capitalized interest
and other (2) 19 24 33 51 48
----------------------------------------------------------------------------
Total Oil Sands
Mining and
Upgrading 541 430 227 1,610 778
----------------------------------------------------------------------------
Horizon coker
rebuild and
collateral damage
costs (3) - - 15 - 404
Midstream 4 5 - 14 5
Abandonments (4) 41 48 66 204 213
Head office 11 10 2 36 18
----------------------------------------------------------------------------
Total net capital
expenditures $ 1,767 $ 1,621 $ 1,909 $ 6,308 $ 6,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 1,086 $ 1,029 $ 1,546 $ 4,126 $ 4,736
North Sea 55 79 71 254 227
Offshore Africa 29 20 (18) 64 33
Oil Sands Mining and
Upgrading 541 430 242 1,610 1,182
Midstream 4 5 - 14 5
Abandonments (4) 41 48 66 204 213
Head office 11 10 2 36 18
----------------------------------------------------------------------------
Total $ 1,767 $ 1,621 $ 1,909 $ 6,308 $ 6,414
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The net capital expenditures exclude adjustments related to
differences between carrying amounts and tax values, and other fair
value adjustments.
(2) Capitalized interest and other includes expenditures related
to land acquisition and retention, seismic, and other
adjustments.
(3) During 2011, the Company recognized $393 million of property
damage insurance recoveries (see note 7 to the interim consolidated
financial statements), offsetting the costs incurred related to the
coker rebuild and collateral damage costs.
(4) Abandonments represent expenditures to settle asset
retirement obligations and have been reflected as capital
expenditures in this table.
The Company's strategy is focused on building a diversified
asset base that is balanced among various products. In order to
facilitate efficient operations, the Company concentrates its
activities in core areas. The Company focuses on maintaining its
land inventories to enable the continuous exploitation of play
types and geological trends, greatly reducing overall exploration
risk. By owning associated infrastructure, the Company is able to
maximize utilization of its production facilities, thereby
increasing control over production costs.
Net capital expenditures for the year ended December 31, 2012
were $6,308 million, comparable with $6,414 million for the year
ended December 31, 2011. Net capital expenditures for the fourth
quarter of 2012 were $1,767 million compared with $1,909 million
for the fourth quarter of 2011 and $1,621 million for the third
quarter of 2012.
The increase in capital expenditures in the Exploration and
Production and Oil Sands Mining and Upgrading segments for the year
ended December 31, 2012 from the comparable period in 2011 was
primarily due to the ramp up of Horizon site construction activity
and an increase in production and related facilities spending,
partially offset by lower net property acquisition costs. The
decrease in capital expenditures for the fourth quarter of 2012
from the comparable period in 2011 was due to lower exploration and
evaluation expenditures and lower net property acquisitions,
partially offset by an increase in Horizon site construction costs.
The increase in capital expenditures from the third quarter of 2012
was primarily due to an increase in well drilling and completion
activities and an increase in Horizon site construction
activity.
Drilling Activity (number of wells)
Year
Three Months Ended Ended
--------------------------------------------------
Dec 31 Sep 30 Dec 31 Dec 31 Dec 31
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net successful natural gas
wells 3 9 27 35 83
Net successful crude oil
wells (1) 294 365 330 1,203 1,103
Dry wells 19 6 17 33 48
Stratigraphic test /
service wells 116 22 112 727 657
----------------------------------------------------------------------------
Total 432 402 486 1,998 1,891
Success rate (excluding
stratigraphic test /
service wells) 94% 99% 95% 97% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes bitumen wells.
North America
North America, excluding Oil Sands Mining and Upgrading,
accounted for approximately 69% of the total capital expenditures
for the year ended December 31, 2012 compared with approximately
77% for the year ended December 31, 2011.
During the fourth quarter of 2012, the Company targeted 3 net
natural gas wells, including 1 well in Northeast British Columbia
and 2 wells in Northwest Alberta. The Company also targeted 313 net
crude oil wells. The majority of these wells were concentrated in
the Company's Northern Plains region where 226 primary heavy crude
oil wells, 15 Pelican Lake heavy crude oil wells, 2 light crude oil
wells and 38 bitumen (thermal oil) wells were drilled. Another 32
wells targeting light crude oil were drilled outside the Northern
Plains region.
Overall Primrose thermal production for the fourth quarter of
2012 averaged approximately 121,000 bbl/d compared with
approximately 78,000 bbl/d for the fourth quarter of 2011 and
approximately 102,000 bbl/d for the third quarter of 2012.
Production volumes were in line with expectations due to the cyclic
nature of thermal production at Primrose. As part of the phased
expansion of its in situ Oil Sands assets, the Company is
continuing to develop its Primrose thermal projects. Additional pad
drilling was completed and drilled on budget, with these wells
coming on production in 2013.
The next planned phase of the Company's in situ Oil Sands assets
expansion is the Kirby South Phase 1 Project. As at December 31,
2012, the overall project was 81% complete, drilling was completed
on the fifth of seven pads, and first steam is targeted for late
2013. In 2012, the Company acquired approximately 49 sections
(12,630 hectares) of additional Oil Sands rights immediately
adjacent to the Kirby Project.
Development of the tertiary recovery conversion projects at
Pelican Lake continued and 15 horizontal wells were drilled during
the quarter. Pelican Lake production averaged approximately 36,000
bbl/d for the fourth quarter of 2012 compared with 40,000 bbl/d for
the fourth quarter of 2011 and 41,000 bbl/d for the third quarter
of 2012. The decrease in production in the fourth quarter of 2012
from the third quarter of 2012 was a result of facility
constraints, which will be alleviated as a result of the completion
of the new 20,000 bbl/d battery expansion targeted to be on stream
in the second quarter of 2013. With this incremental capacity, both
Woodenhouse and Pelican production volumes will no longer be
restricted.
For the first quarter of 2013, the Company's overall planned
drilling activity in North America is expected to be 265 net crude
oil wells, 31 net bitumen wells and 15 net natural gas wells,
excluding stratigraphic and service wells.
Oil Sands Mining and Upgrading
Phase 2/3 expansion activity in the fourth quarter of 2012 was
focused on the field construction of the gas recovery unit, sulphur
recovery unit, butane treatment unit, coker expansion, and
extraction trains 3 and 4, along with engineering related to the
hydrogen and hydrotreater units, vacuum distillation unit and
distillation recovery unit.
North Sea
In December 2011, the Banff FPSO and subsea infrastructure
suffered storm damage. Operations at Banff/Kyle, with combined net
production of approximately 3,500 bbl/d, were suspended. The FPSO
and associated floating storage unit have subsequently been removed
from the field and the FPSO is currently in dry dock for assessment
of the damage and repair timeframe. The extent of the property
damage, including associated costs, is not expected to be
significant.
In September 2012, the UK government announced the
implementation of the Brownfield Allowance, which allows for an
agreed allowance related to property development for certain
pre-approved qualifying field developments. This allowance
partially mitigates the impact of previous tax increases. The
Company is currently assessing the impact of this initiative on its
future capital programs.
The Company currently plans to decommission the Murchison
platform in the North Sea commencing in 2014 and estimates the
decommissioning efforts will continue for approximately 5
years.
Offshore Africa
During the fourth quarter of 2011, the Company sanctioned an 8
well drilling program at the Espoir field in Cote d'Ivoire.
Preparations are ongoing and a drilling rig is on-site in
preparation for the commencement of the drilling program in 2013.
At the Olowi field in Gabon, approximately 1,500 bbl/d of
production was shut in due to a failure in the midwater arch. The
Company currently has a vessel on-site assessing the operability of
the midwater arch.
LIQUIDITY AND CAPITAL RESOURCES
------------------------------------
Dec 31 Sep 30 Dec 31
($ millions, except ratios) 2012 2012 2011
----------------------------------------------------------------------------
Working capital (deficit) (1) $ (1,264) $ (1,002) $ (894)
Long-term debt (2) (3) $ 8,736 $ 8,416 $ 8,571
Share capital $ 3,709 $ 3,691 $ 3,507
Retained earnings 20,516 20,383 19,365
Accumulated other comprehensive income 58 46 26
----------------------------------------------------------------------------
Shareholders' equity $ 24,283 $ 24,120 $ 22,898
Debt to book capitalization (3) (4) 26% 26% 27%
Debt to market capitalization (3) (5) 22% 20% 17%
After-tax return on average common
shareholders' equity (6) 8% 10% 12%
After-tax return on average capital
employed (3) (7) 7% 8% 10%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated as current assets less current liabilities,
excluding the current portion of long-term debt.
(2) Includes the current portion of long-term debt.
(3) Long-term debt is stated at its carrying value, net of fair
value adjustments, original issue discounts and transaction
costs.
(4) Calculated as current and long-term debt; divided by the
book value of common shareholders' equity plus current and
long-term debt.
(5) Calculated as current and long-term debt; divided by the
market value of common shareholders' equity plus current and
long-term debt.
(6) Calculated as net earnings for the twelve month trailing
period; as a percentage of average common shareholders' equity for
the period.
(7) Calculated as net earnings plus after-tax interest and other
financing costs for the twelve month trailing period; as a
percentage of average capital employed for the period.
At December 31, 2012, the Company's capital resources consisted
primarily of cash flow from operations, available bank credit
facilities and access to debt capital markets. Cash flow from
operations and the Company's ability to renew existing bank credit
facilities and raise new debt is dependent on factors discussed in
the "Risks and Uncertainties" section of the Company's December 31,
2011 annual MD&A. In addition, the Company's ability to renew
existing bank credit facilities and raise new debt is also
dependent upon maintaining an investment grade debt rating and the
condition of capital and credit markets. The Company continues to
believe that its internally generated cash flow from operations
supported by the implementation of its ongoing hedge policy, the
flexibility of its capital expenditure programs supported by its
multi-year financial plans, its existing bank credit facilities,
and its ability to raise new debt on commercially acceptable terms
will provide sufficient liquidity to sustain its operations in the
short, medium and long term and support its growth strategy. At
December 31, 2012, the Company had $3,661 million of available
credit under its bank credit facilities.
During the second quarter of 2012, the Company's $1,500 million
revolving syndicated credit facility was extended to June 2016.
Additionally, the Company issued $500 million of 3.05% medium-term
notes due June 2019. Proceeds from the securities issued were used
to repay bank indebtedness and for general corporate purposes.
After issuing these securities, the Company has $2,500 million
remaining on its outstanding $3,000 million base shelf prospectus
that allows for the issue of medium-term notes in Canada, which
expires in November 2013. If issued, these securities will bear
interest as determined at the date of issuance.
During the fourth quarter of 2012, the Company repaid US$350
million of 5.45% unsecured notes. The Company has US$2,000 million
remaining on its outstanding US$3,000 million base shelf prospectus
that allows for the issue of US dollar debt securities in the
United States, which expires in November 2013. If issued, these
securities will bear interest as determined at the date of
issuance.
Subsequent to December 31, 2012, $400 million of 4.50% medium
term notes and US$400 million of 5.15% unsecured notes were repaid.
This indebtedness was retired utilizing cash flow from operations
generated in excess of capital expenditures and available bank
credit facilities as necessary, while maintaining the ongoing
dividend program. On a pro forma basis, reflecting the retirement
of this indebtedness at December 31, 2012, the available credit
under its bank credit facilities would amount to $2,863
million.
Long-term debt was $8,736 million at December 31, 2012,
resulting in a debt to book capitalization ratio of 26% (September
30, 2012 - 26%; December 31, 2011 - 27%). This ratio is within the
25% to 45% internal range utilized by management. This range may be
exceeded in periods when a combination of capital projects,
acquisitions, or lower commodity prices occurs. The Company may be
below the low end of the targeted range when cash flow from
operating activities is greater than current investment activities.
The Company remains committed to maintaining a strong balance
sheet, adequate available liquidity and a flexible capital
structure. The Company has hedged a portion of its crude oil
production for 2013 at prices that protect investment returns to
ensure ongoing balance sheet strength and the completion of its
capital expenditure programs. Further details related to the
Company's long-term debt at December 31, 2012 are discussed in note
5 to the Company's unaudited interim consolidated financial
statements.
The Company's commodity hedging policy reduces the risk of
volatility in commodity prices and supports the Company's cash flow
for its capital expenditures programs. This policy currently allows
for the hedging of up to 60% of the near 12 months budgeted
production and up to 40% of the following 13 to 24 months estimated
production. For the purpose of this policy, the purchase of put
options is in addition to the above parameters. As at March 6,
2013, approximately 48% of currently forecasted 2013 crude oil
volumes were hedged using price collars. Further details related to
the Company's commodity related derivative financial instruments
outstanding at December 31, 2012 are discussed in note 13 to the
Company's unaudited interim consolidated financial statements.
Share Capital
As at December 31, 2012, there were 1,092,072,000 common shares
outstanding and 73,747,000 stock options outstanding. As at March
5, 2013, the Company had 1,092,589,000 common shares outstanding
and 68,482,000 stock options outstanding.
During the second quarter of 2012, the Company amended its
Articles by special resolution of the Shareholders, changing the
designation of its Class 1 preferred shares to "Preferred Shares"
which may be issuable in series. If issued, the number of shares in
each series, and the designation, rights, privileges, restrictions
and conditions attached to the shares will be determined by the
Board of Directors of the Company.
On March 6, 2013, the Company's Board of Directors approved an
increase in the annual dividend to be paid by the Company to $0.50
per common share for 2013. The increase represents an approximately
19% increase from 2012, recognizing the stability of the Company's
cash flow and providing a return to shareholders. The dividend
policy undergoes periodic review by the Board of Directors and is
subject to change. In March 2012, an increase in the annual
dividend paid by the Company to $0.42 per common share was approved
for 2012. The increase represented a 17% increase from 2011.
In April 2012, the Company announced a Normal Course Issuer Bid
to purchase, through the facilities of the Toronto Stock Exchange
("TSX") and the New York Stock Exchange ("NYSE"), during the twelve
month period commencing April 9, 2012 and ending April 8, 2013, up
to 55,027,447 common shares.
On March 31, 2011, the Company announced a Normal Course Issuer
Bid to purchase, through the facilities of the TSX and the NYSE,
during the twelve month period commencing April 6, 2011 and ending
April 5, 2012, up to 27,406,131 common shares of the Company.
As at December 31, 2012, 11,012,700 common shares were purchased
for cancellation at a weighted average price of $28.91 per common
share, for a total cost of $318 million.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. As at December 31, 2012, no entities were
consolidated under the Standing Interpretations Committee ("SIC")
12, "Consolidation - Special Purpose Entities". The following table
summarizes the Company's commitments as at December 31, 2012:
($ millions) 2013 2014 2015 2016 2017 Thereafter
----------------------------------------------------------------------------
Product
transport
ation and
pipeline $ 231 $ 218 $ 204 $ 135 $ 117 $ 788
Offshore
equipment
operating
leases
and
offshore
drilling $ 156 $ 135 $ 104 $ 76 $ 57 $ 65
Long-term
debt (1) $ 798 $ 846 $ 593 $ 1,027 $ 1,094 $ 4,430
Interest
and other
financing
costs (2) $ 414 $ 395 $ 359 $ 338 $ 283 $ 3,782
Office
leases $ 33 $ 34 $ 32 $ 33 $ 35 $ 262
Other $ 173 $ 95 $ 43 $ 10 $ 2 $ 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does
not reflect fair value adjustments, original issue discounts or
transaction costs.
(2) Interest and other financing cost amounts represent the
scheduled fixed rate and variable rate cash interest payments
related to long-term debt. Interest on variable rate long-term debt
was estimated based upon prevailing interest rates and foreign
exchange rates as at December 31, 2012.
In addition to the commitments disclosed above, the Company has
entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These
contracts can be cancelled by the Company upon notice without
penalty, subject to the costs incurred up to and in respect of the
cancellation.
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is a defendant and plaintiff in a number of legal
actions arising in the normal course of business. In addition, the
Company is subject to certain contractor construction claims. The
Company believes that any liabilities that might arise pertaining
to any such matters would not have a material effect on its
consolidated financial position.
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
For the impact of new accounting standards, refer to the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2011.
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING
POLICIES
The preparation of financial statements requires the Company to
make estimates, assumptions and judgments in the application of
IFRS that have a significant impact on the financial results of the
Company. Actual results could differ from estimated amounts, and
those differences may be material. A comprehensive discussion of
the Company's significant accounting policies is contained in the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2011.
Consolidated Balance Sheets
--------------------------------
As at Dec 31 Dec 31
(millions of Canadian dollars, unaudited) Note 2012 2011
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 37 $ 34
Accounts receivable 1,197 2,077
Inventory 554 550
Prepaids and other 126 120
----------------------------------------------------------------------------
1,914 2,781
Exploration and evaluation assets 2 2,611 2,475
Property, plant and equipment 3 44,028 41,631
Other long-term assets 4 427 391
----------------------------------------------------------------------------
$ 48,980 $ 47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 465 $ 526
Accrued liabilities 2,273 2,347
Current income tax liabilities 285 347
Current portion of long-term debt 5 798 359
Current portion of other long-term
liabilities 6 155 455
----------------------------------------------------------------------------
3,976 4,034
Long-term debt 5 7,938 8,212
Other long-term liabilities 6 4,609 3,913
Deferred income tax liabilities 8,174 8,221
----------------------------------------------------------------------------
24,697 24,380
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital 9 3,709 3,507
Retained earnings 20,516 19,365
Accumulated other comprehensive income 10 58 26
----------------------------------------------------------------------------
24,283 22,898
----------------------------------------------------------------------------
$ 48,980 $ 47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments and contingencies (note 14).
Approved by the Board of Directors on March 6, 2013
Consolidated Statements of Earnings
Three Months Ended Year Ended
------------------------------------------------
(millions of Canadian
dollars, except per
common share amounts, Dec 31 Dec 31 Dec 31 Dec 31
unaudited) Note 2012 2011 2012 2011
----------------------------------------------------------------------------
Product sales $ 4,059 $ 4,788 $ 16,195 $ 15,507
Less: royalties (359) (570) (1,606) (1,715)
----------------------------------------------------------------------------
Revenue 3,700 4,218 14,589 13,792
----------------------------------------------------------------------------
Expenses
Production 1,072 1,034 4,249 3,671
Transportation and
blending 738 582 2,752 2,327
Depletion, depreciation
and amortization 3 1,213 998 4,328 3,604
Administration 64 47 270 235
Share-based compensation 6 (41) 207 (214) (102)
Asset retirement
obligation accretion 6 38 33 151 130
Interest and other
financing costs 83 83 364 373
Risk management
activities 13 - 78 120 (27)
Foreign exchange loss
(gain) 58 (106) (49) 1
Horizon asset impairment
provision 7 - - - 396
Insurance recovery -
property damage 7 - 3 - (393)
Insurance recovery -
business interruption 7 - (16) - (333)
Equity loss from jointly
controlled entity 4 3 - 9 -
----------------------------------------------------------------------------
3,228 2,943 11,980 9,882
----------------------------------------------------------------------------
Earnings before taxes 472 1,275 2,609 3,910
Current income tax
expense 8 189 299 747 860
Deferred income tax
(recovery) expense 8 (69) 144 (30) 407
----------------------------------------------------------------------------
Net earnings $ 352 $ 832 $ 1,892 $ 2,643
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common
share
Basic 12 $ 0.32 $ 0.76 $ 1.72 $ 2.41
Diluted 12 $ 0.32 $ 0.76 $ 1.72 $ 2.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income
------------------------------------------------
Three Months Ended Year Ended
------------------------------------------------
(millions of Canadian Dec 31 Dec 31 Dec 31 Dec 31
dollars, unaudited) 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings $ 352 $ 832 $ 1,892 $ 2,643
----------------------------------------------------------------------------
Net change in derivative
financial instruments
designated as cash flow
hedges
Unrealized income (loss)
during the period, net of
taxes of $2 million (2011
- $10 million) - three
months ended;$4 million
(2011 - $5 million) -
year ended 17 (67) 31 (23)
Reclassification to net
earnings, net of taxes of
$nil (2011 - $4 million)
- three months ended;$nil
(2011 - $17 million) -
year ended (3) 11 (7) 52
----------------------------------------------------------------------------
14 (56) 24 29
Foreign currency translation
adjustment
Translation of net
investment (2) 11 8 (12)
----------------------------------------------------------------------------
Other comprehensive income
(loss), net of taxes 12 (45) 32 17
----------------------------------------------------------------------------
Comprehensive income $ 364 $ 787 $ 1,924 $ 2,660
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Changes in Equity
Year Ended
------------------------------
Dec 31 Dec 31
(millions of Canadian dollars, unaudited) Note 2012 2011
----------------------------------------------------------------------------
Share capital 9
Balance - beginning of year $ 3,507 $ 3,147
Issued upon exercise of stock options 194 255
Previously recognized liability on stock
options exercised for common shares 45 115
Purchase of common shares under Normal
Course Issuer Bid (37) (10)
----------------------------------------------------------------------------
Balance - end of year 3,709 3,507
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of year 19,365 17,212
Net earnings 1,892 2,643
Purchase of common shares under Normal
Course Issuer Bid 9 (281) (94)
Dividends on common shares 9 (460) (396)
----------------------------------------------------------------------------
Balance - end of year 20,516 19,365
----------------------------------------------------------------------------
Accumulated other comprehensive income 10
Balance - beginning of year 26 9
Other comprehensive income, net of taxes 32 17
----------------------------------------------------------------------------
Balance - end of year 58 26
----------------------------------------------------------------------------
Shareholders' equity $ 24,283 $ 22,898
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Three Months Ended Year Ended
------------------------------------------------
(millions of Canadian Dec 31 Dec 31 Dec 31 Dec 31
dollars, unaudited) Note 2012 2011 2012 2011
----------------------------------------------------------------------------
Operating activities
Net earnings $ 352 $ 832 $ 1,892 $ 2,643
Non-cash items
Depletion, depreciation
and amortization 1,213 998 4,328 3,604
Share-based compensation (41) 207 (214) (102)
Asset retirement
obligation accretion 38 33 151 130
Unrealized risk management
loss (gain) 8 58 (42) (128)
Unrealized foreign
exchange loss (gain) 254 (117) 129 215
Realized foreign exchange
gain on repayment of US
dollar debt securities (210) - (210) (225)
Equity loss from jointly
controlled entity 3 - 9 -
Deferred income tax
(recovery) expense (69) 144 (30) 407
Horizon asset impairment
provision 7 - - - 396
Insurance recovery -
property damage 7 - 3 - (393)
Other (94) (46) (47) (55)
Abandonment expenditures (41) (66) (204) (213)
Net change in non-cash
working capital 202 267 447 (36)
----------------------------------------------------------------------------
1,615 2,313 6,209 6,243
----------------------------------------------------------------------------
Financing activities
Issue (repayment) of bank
credit facilities, net 592 (1,632) 172 (647)
Issue of medium-term notes,
net - - 498 -
(Repayment) issue of US
dollar debt securities, net 5 (344) 1,011 (344) 621
Issue of common shares on
exercise of stock options 30 63 194 255
Purchase of common shares
under Normal Course Issuer
Bid (118) (12) (318) (104)
Dividends on common shares (115) (99) (444) (378)
Net change in non-cash
working capital (8) (5) (37) (15)
----------------------------------------------------------------------------
37 (674) (279) (268)
----------------------------------------------------------------------------
Investing activities
Expenditures on exploration
and evaluation assets and
property, plant and
equipment (1,726) (1,843) (6,104) (6,201)
Investment in other long-
term assets - 25 2 (321)
Net change in non-cash
working capital 90 195 175 559
----------------------------------------------------------------------------
(1,636) (1,623) (5,927) (5,963)
----------------------------------------------------------------------------
Increase in cash and cash
equivalents 16 16 3 12
Cash and cash equivalents -
beginning of period 21 18 34 22
----------------------------------------------------------------------------
Cash and cash equivalents
-end of period $ 37 $ 34 $ 37 $ 34
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 104 $ 80 $ 464 $ 456
Income taxes paid $ 105 $ 190 $ 639 $ 706
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes to the Consolidated Financial Statements
(tabular amounts in millions of Canadian dollars, unless
otherwise stated, unaudited)
1. ACCOUNTING POLICIES
Canadian Natural Resources Limited (the "Company") is a senior
independent crude oil and natural gas exploration, development and
production company. The Company's exploration and production
operations are focused in North America, largely in Western Canada;
the United Kingdom ("UK") portion of the North Sea; and Cote
d'Ivoire, Gabon, and South Africa in Offshore Africa.
The Horizon Oil Sands Mining and Upgrading segment ("Horizon")
produces synthetic crude oil through bitumen mining and upgrading
operations.
Within Western Canada, the Company maintains certain midstream
activities that include pipeline operations, an electricity
co-generation system and an investment in the North West Redwater
Partnership ("Redwater").
The Company was incorporated in Alberta, Canada. The address of
its registered office is 2500, 855-2 Street S.W., Calgary, Alberta,
Canada
These interim consolidated financial statements and the related
notes have been prepared in accordance with International Financial
Reporting Standards ("IFRS") as issued by the International
Accounting Standards Board, applicable to the preparation of
interim financial statements, including International Accounting
Standard ("IAS") 34, "Interim Financial Reporting", following the
same accounting policies as the audited consolidated financial
statements of the Company as at December 31, 2011. These interim
consolidated financial statements contain disclosures that are
supplemental to the Company's annual audited consolidated financial
statements. Certain disclosures that are normally required to be
included in the notes to the annual audited consolidated financial
statements have been condensed. These interim consolidated
financial statements should be read in conjunction with the
Company's audited consolidated financial statements and notes
thereto for the year ended December 31, 2011.
2. EXPLORATION AND EVALUATION ASSETS
Oil Sands
Mining and
Exploration and Production Upgrading Total
----------------------------------------------------------------------------
North Offshore
America North Sea Africa
----------------------------------------------------------------------------
Cost
At December 31,
2011 $ 2,442 $ - $ 33 $ - $ 2,475
Additions 295 - 14 - 309
Transfers to
property, plant
and equipment (173) - - - (173)
----------------------------------------------------------------------------
At December 31,
2012 $ 2,564 $ - $ 47 $ - $ 2,611
----------------------------------------------------------------------------
----------------------------------------------------------------------------
3. PROPERTY, PLANT AND EQUIPMENT
Exploration and Production
----------------------------------------------------------------------------
North Offshore
America North Sea Africa
----------------------------------------------------------------------------
Cost
At December 31, 2011 $ 46,120 $ 4,147 $ 3,044
Additions 4,160 556 75
Transfers from E&E
assets 173 - -
Disposals/
derecognitions (129) (39) (8)
Foreign exchange
adjustments and
other - (90) (66)
----------------------------------------------------------------------------
At December 31, 2012 $ 50,324 $ 4,574 $ 3,045
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and depreciation
At December 31, 2011 $ 21,721 $ 2,512 $ 2,152
Expense 3,399 294 165
Disposals/
derecognitions (129) (39) (6)
Foreign exchange
adjustments and
other - (58) (38)
----------------------------------------------------------------------------
At December 31, 2012 $ 24,991 $ 2,709 $ 2,273
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value- at
December 31, 2012 $ 25,333 $ 1,865 $ 772
- at December 31,
2011 $ 24,399 $ 1,635 $ 892
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil Sands
Mining and
Upgrading Midstream Head Office Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cost
At December 31, 2011$ 15,211 $ 298$ 234$ 69,054
Additions 1,757 14 36 6,598
Transfers from E&E
assets - - - 173
Disposals/
derecognitions (5) - - (181)
Foreign exchange
adjustments and
other - - - (156)
----------------------------------------------------------------------------
At December 31, 2012$ 16,963 $ 312$ 270$ 75,488
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and
depreciation
At December 31, 2011$ 776 $ 96$ 166$ 27,423
Expense 447 7 16 4,328
Disposals/
derecognitions (5) - - (179)
Foreign exchange
adjustments and
other (16) - - (112)
----------------------------------------------------------------------------
At December 31, 2012$ 1,202 $ 103$ 182$ 31,460
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value- at
December 31, 2012 $ 15,761 $ 209$ 88$ 44,028
- at December 31,
2011 $ 14,435 $ 202$ 68$ 41,631
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Horizon project costs not subject to depletion
----------------------------------------------------------------------------
At December 31, 2012 $ 2,066
At December 31, 2011 $ 1,443
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In addition, the Company has capitalized costs to date of $1,021
million (2011 - $528 million) related to the development of the
Kirby Thermal Oil Sands Project which are not subject to
depletion.
During 2012, the Company acquired a number of producing crude
oil and natural gas assets in the North American Exploration and
Production segment for total cash consideration of $144 million
(year ended December 31, 2011 - $1,012 million), net of associated
asset retirement obligations of $12 million (year ended December
31, 2011 - $79 million). Interests in jointly controlled assets
were acquired with full tax basis. No working capital or debt
obligations were assumed.
The Company capitalizes construction period interest for
qualifying assets based on costs incurred and the Company's cost of
borrowing. Interest capitalization to a qualifying asset ceases
once construction is substantially complete. During 2012, pre-tax
interest of $98 million was capitalized to property, plant and
equipment (December 31, 2011 - $59 million) using a capitalization
rate of 4.8% (December 31, 2011 - 4.7%).
4. OTHER LONG-TERM ASSETS
-------------
Dec 31 Dec 31
2012 2011
----------------------------------------------------------------------------
Investment in North West Redwater Partnership $ 310 $ 321
Other 117 70
----------------------------------------------------------------------------
$ 427 $ 391
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other long-term assets include an investment in the 50% owned
Redwater. The investment is accounted for using the equity method.
Redwater has entered into an agreement to construct and operate a
50,000 barrel per day bitumen upgrader and refinery (the "Project")
under processing agreements that target to process 12,500 barrels
per day of bitumen feedstock for the Company and 37,500 barrels per
day of bitumen feedstock for the Alberta Petroleum Marketing
Commission, an agent of the Government of Alberta, under a 30 year
fee-for-service tolling agreement. During 2012, the Project
received board sanction from Redwater and its partners.
Redwater has entered into various agreements related to the
engineering and procurement of the Project. These contracts can be
cancelled by Redwater upon notice without penalty, subject to the
costs incurred up to and in respect of the cancellation.
5. LONG-TERM DEBT
------------
Dec 31 Dec 31
2012 2011
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities $ 971 $ 796
Medium-term notes 1,300 800
----------------------------------------------------------------------------
2,271 1,596
----------------------------------------------------------------------------
US dollar denominated debt
US dollar debt securities (December 31, 2012 -
US$6,550 million; December 31, 2011 - US$6,900
million) 6,517 7,017
Less: original issue discount on US dollar debt
securities (1) (20) (21)
----------------------------------------------------------------------------
6,497 6,996
Fair value impact of interest rate swaps on US
dollar debt securities (2) 19 31
----------------------------------------------------------------------------
6,516 7,027
----------------------------------------------------------------------------
Long-term debt before transaction costs 8,787 8,623
Less: transaction costs (1) (3) (51) (52)
----------------------------------------------------------------------------
8,736 8,571
Less: current portion (1) (2) (4) 798 359
----------------------------------------------------------------------------
$ 7,938 $ 8,212
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has included unamortized original issue discounts and
directly attributable transaction costs in the carrying amount of the
outstanding debt.
(2) The carrying amount of US$350 million of 4.90% unsecured notes due
December 2014 was adjusted by $19 million to reflect the fair
value impact of hedge accounting. At December 31, 2011, the
carrying amounts of US$350 million of 5.45% unsecured notes
due October 2012 and US$350 million of 4.90% unsecured notes due
December 2014 were adjusted by $31 million to reflect the fair value
impact of hedge accounting.
(3) Transaction costs primarily represent underwriting commissions charged
as a percentage of the related debt offerings, as well as legal, rating
agency and other professional fees.
(4) Subsequent to December 31, 2012, $400 million of 4.50% medium term notes
due January 2013 and US$400 million of 5.15% unsecured notes due
February 2013 were repaid. This indebtedness was retired utilizing cash
flow from operating activities generated in excess of capital
expenditures and available bank credit facilities as necessary.
Bank Credit Facilities
As at December 31, 2012, the Company had in place unsecured bank
credit facilities of $4,724 million, comprised of:
-- a $200 million demand credit facility;
-- a revolving syndicated credit facility of $3,000 million
maturing June 2015;
-- a revolving syndicated credit facility of $1,500 million
maturing June 2016; and
-- a GBP 15 million demand credit facility related to the
Company's North Sea operations.
During the second quarter of 2012, the $1,500 million revolving
syndicated credit facility was extended to June 2016. Each of the
$3,000 million and $1,500 million facilities is extendible annually
for one-year periods at the mutual agreement of the Company and the
lenders. If the facilities are not extended, the full amount of the
outstanding principal would be repayable on the maturity date.
Borrowings under these facilities may be made by way of pricing
referenced to Canadian dollar or US dollar bankers' acceptances, or
LIBOR, US base rate or Canadian prime loans.
The Company's weighted average interest rate on bank credit
facilities outstanding as at December 31, 2012, was 2.2% (December
31, 2011 - 2.2%), and on long-term debt outstanding for the year
ended December 31, 2012 was 4.8% (December 31, 2011 - 4.7%).
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $467 million, including an $87
million financial guarantee related to Horizon and $276 million of
letters of credit related to North Sea operations, were outstanding
at December 31, 2012. Subsequent to December 31, 2012, the letter
of credit related to North Sea operations was increased to $347
million.
Medium-Term Notes
During the second quarter of 2012, the Company issued $500
million of 3.05% medium-term notes due June 2019. After issuing
these securities, the Company has $2,500 million remaining on its
outstanding $3,000 million base shelf prospectus that allows for
the issue of medium-term notes in Canada, which expires in November
2013. If issued, these securities will bear interest as determined
at the date of issuance.
US Dollar Debt Securities
During the fourth quarter of 2012, the Company repaid US$350
million of 5.45% unsecured notes.
During 2011, the Company repaid US$400 million of 6.70%
unsecured notes and issued US$1,000 million of unsecured notes
under the US base shelf prospectus, comprised of US$500 million of
1.45% unsecured notes due November 2014 and US$500 million of 3.45%
unsecured notes due November 2021. Concurrently, the Company
entered into cross currency swaps to fix the Canadian dollar
interest and principal repayment amounts on the US$500 million of
3.45% unsecured notes due November 2021 at 3.96% and C$511 million
(note 13).
The Company has US$2,000 million remaining on its outstanding
US$3,000 million base shelf prospectus that allows for the issue of
US dollar debt securities in the United States, which expires in
November 2013. If issued, these securities will bear interest as
determined at the date of issuance.
6. OTHER LONG-TERM LIABILITIES
-------------
Dec 31 Dec 31
2012 2011
----------------------------------------------------------------------------
Asset retirement obligations $ 4,266 $ 3,577
Share-based compensation 154 432
Risk management (note 13) 257 274
Other 87 85
----------------------------------------------------------------------------
4,764 4,368
Less: current portion 155 455
----------------------------------------------------------------------------
$ 4,609 $ 3,913
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's asset retirement obligations are expected to be
settled on an ongoing basis over a period of approximately 60 years
and have been discounted using a weighted average discount rate of
4.3% (December 31, 2011 - 4.6%). A reconciliation of the discounted
asset retirement obligations is as follows:
-------------
Dec 31 Dec 31
2012 2011
----------------------------------------------------------------------------
Balance - beginning of year $ 3,577 $ 2,624
Liabilities incurred 51 42
Liabilities acquired 12 79
Liabilities settled (204) (213)
Asset retirement obligation accretion 151 130
Revision of estimates 384 472
Change in discount rate 315 422
Foreign exchange (20) 21
----------------------------------------------------------------------------
Balance - end of year $ 4,266 $ 3,577
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Share-based compensation
As the Company's Option Plan provides current employees with the
right to elect to receive common shares or a cash payment in
exchange for stock options surrendered, a liability for potential
cash settlements is recognized. The current portion represents the
maximum amount of the liability payable within the next twelve
month period if all vested stock options are surrendered for cash
settlement.
-------------
Dec 31 Dec 31
2012 2011
----------------------------------------------------------------------------
Balance - beginning of year $ 432 $ 663
Share-based compensation recovery (214) (102)
Cash payment for stock options surrendered (7) (14)
Transferred to common shares (45) (115)
Recovered from Oil Sands Mining and Upgrading (12) -
----------------------------------------------------------------------------
Balance - end of year 154 432
Less: current portion 129 384
----------------------------------------------------------------------------
$ 25 $ 48
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. HORIZON ASSET IMPAIRMENT PROVISION AND INSURANCE RECOVERY
In 2011, the Company recognized an asset impairment provision in
the Oil Sands Mining and Upgrading segment of $396 million, net of
accumulated depletion and amortization, related to the property
damage resulting from a fire in the Horizon primary upgrading
coking plant. The Company also recorded final property damage
insurance recoveries of $393 million and business interruption
insurance recoveries of $333 million in 2011. In the first quarter
of 2012, upon final settlement of its insurance claims, all
outstanding insurance proceeds were collected.
8. INCOME TAXES
The provision for income tax is as follows:
Three Months Ended Year Ended
----------------------------------------------------
Dec 31 Dec 31 Dec 31 Dec 31
2012 2011 2012 2011
----------------------------------------------------------------------------
Current corporate income
tax - North America $ 68 $ 119 $ 366 $ 315
Current corporate income
tax - North Sea 29 84 115 245
Current corporate income
tax - Offshore Africa 56 50 206 140
Current PRT (1) expense
- North Sea 31 39 44 135
Other taxes 5 7 16 25
----------------------------------------------------------------------------
Current income tax
expense 189 299 747 860
----------------------------------------------------------------------------
Deferred corporate
income tax (recovery)
expense (34) 157 - 412
Deferred PRT (1)
(recovery) - North Sea (35) (13) (30) (5)
----------------------------------------------------------------------------
Deferred income tax
(recovery) expense (69) 144 (30) 407
----------------------------------------------------------------------------
Income tax expense $ 120 $ 443 $ 717 $ 1,267
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Petroleum Revenue Tax.
During the third quarter of 2012, the UK government enacted
legislation to restrict the combined corporate and supplementary
income tax relief on UK North Sea decommissioning expenditures to
50%. As a result of the income tax rate change, the Company's
deferred income tax liability was increased by $58 million.
During the first quarter of 2011, the UK government enacted
legislation to increase the supplementary income tax rate charged
on profits from UK North Sea crude oil and natural gas production,
increasing the combined corporate and supplementary income tax rate
from 50% to 62%. As a result of the income tax rate change, the
Company's deferred income tax liability was increased by $104
million.
During 2011, the Canadian federal government enacted legislation
to implement several taxation changes. These changes include a
requirement that, beginning in 2012, partnership income must be
included in the taxable income of each corporate partner based on
the tax year of the partner, rather than the fiscal year of the
partnership. The legislation includes a five-year transition
provision and has no impact on net earnings.
9. SHARE CAPITAL
Authorized
Preferred shares issuable in a series.
Unlimited number of common shares without par value.
-------------------------------
Year Ended Dec 31, 2012
Number of shares
Issued common shares (thousands) Amount
----------------------------------------------------------------------------
Balance - beginning of year 1,096,460 $ 3,507
Issued upon exercise of stock options 6,625 194
Previously recognized liability on stock
options exercised for common shares - 45
Purchase of common shares under Normal Course
Issuer Bid (11,013) (37)
----------------------------------------------------------------------------
Balance - end of year 1,092,072 $ 3,709
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Preferred Shares
During the second quarter of 2012, the Company amended its
Articles by special resolution of the Shareholders, changing the
designation of its Class 1 preferred shares to "Preferred Shares"
which may be issuable in series. If issued, the number of shares in
each series, and the designation, rights, privileges, restrictions
and conditions attached to the shares will be determined by the
Board of Directors of the Company.
Dividend Policy
The Company has paid regular quarterly dividends in January,
April, July, and October of each year since 2001. The dividend
policy undergoes periodic review by the Board of Directors and is
subject to change.
On March 6, 2013, the Board of Directors set the regular
quarterly dividend at $0.125 per common share (2012 - $0.105 per
common share).
Normal Course Issuer Bid
The Company's Normal Course Issuer Bid announced in 2011 expired
April 5, 2012. In April 2012, the Company announced a Normal Course
Issuer Bid to purchase through the facilities of the Toronto Stock
Exchange and the New York Stock Exchange, during the twelve month
period commencing April 9, 2012 and ending April 8, 2013, up to
55,027,447 common shares.
As at December 31, 2012, the Company purchased 11,012,700 common
shares at a weighted average price of $28.91 per common share, for
a total cost of $318 million. Retained earnings were reduced by
$281 million, representing the excess of the purchase price of
common shares over their average carrying value.
Stock Options
The following table summarizes information relating to stock
options outstanding at December 31, 2012:
------------------------------
Year Ended Dec 31, 2012
----------------------------------------------------------------------------
Weighted
average
Stock options exercise
(thousands) price
----------------------------------------------------------------------------
Outstanding - beginning of year 73,486 $ 34.85
Granted (1) 14,779 $ 29.27
Surrendered for cash settlement (998) $ 29.82
Exercised for common shares (6,625) $ 29.19
Forfeited (1) (6,895) $ 36.68
----------------------------------------------------------------------------
Outstanding - end of year 73,747 $ 34.13
----------------------------------------------------------------------------
Exercisable - end of year 29,366 $ 33.73
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to December 31, 2012, 3,479,000 stock options at a weighted
average exercise price of $28.74 were granted and 8,228,000 stock
options at a weighted average exercise price of $35.27 were forfeited.
The Option Plan is a "rolling 9%" plan, whereby the aggregate
number of common shares that may be reserved for issuance under the
plan shall not exceed 9% of the common shares outstanding from time
to time.
10. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of accumulated other comprehensive income, net of
taxes, were as follows:
-------------
Dec 31 Dec 31
2012 2011
----------------------------------------------------------------------------
Derivative financial instruments designated as
cash flow hedges $ 86 $ 62
Foreign currency translation adjustment (28) (36)
----------------------------------------------------------------------------
$ 58 $ 26
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. CAPITAL DISCLOSURES
The Company does not have any externally imposed regulatory
capital requirements for managing capital. The Company has defined
its capital to mean its long-term debt and consolidated
shareholders' equity, as determined at each reporting date.
The Company's objectives when managing its capital structure are
to maintain financial flexibility and balance to enable the Company
to access capital markets to sustain its on-going operations and to
support its growth strategies. The Company primarily monitors
capital on the basis of an internally derived financial measure
referred to as its "debt to book capitalization ratio", which is
the arithmetic ratio of current and long-term debt divided by the
sum of the carrying value of shareholders' equity plus current and
long-term debt. The Company's internal targeted range for its debt
to book capitalization ratio is 25% to 45%. This range may be
exceeded in periods when a combination of capital projects,
acquisitions, or lower commodity prices occurs. The Company may be
below the low end of the targeted range when cash flow from
operating activities is greater than current investment activities.
At December 31, 2012, the ratio was within the target range at
26%.
Readers are cautioned that the debt to book capitalization ratio
is not defined by IFRS and this financial measure may not be
comparable to similar measures presented by other companies.
Further, there are no assurances that the Company will continue to
use this measure to monitor capital or will not alter the method of
calculation of this measure in the future.
-------------
Dec 31 Dec 31
2012 2011
----------------------------------------------------------------------------
Long-term debt (1) $ 8,736 $ 8,571
Total shareholders' equity $ 24,283 $ 22,898
Debt to book capitalization 26% 27%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
12. NET EARNINGS PER COMMON SHARE
Three Months Ended Year Ended
----------------------------------------------------
Dec 31 Dec 31 Dec 31 Dec 31
2012 2011 2012 2011
----------------------------------------------------------------------------
Weighted average common
shares outstanding -
basic (thousands of
shares) 1,093,925 1,095,072 1,097,084 1,095,582
Effect of dilutive stock
options (thousands of
shares) 1,604 4,390 2,435 7,000
----------------------------------------------------------------------------
Weighted average common
shares outstanding -
diluted (thousands of
shares) 1,095,529 1,099,462 1,099,519 1,102,582
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 352 $ 832 $ 1,892 $ 2,643
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common
share - basic $ 0.32 $ 0.76 $ 1.72 $ 2.41
- diluted $ 0.32 $ 0.76 $ 1.72 $ 2.40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
13. FINANCIAL INSTRUMENTS
The carrying amounts of the Company's financial instruments by
category were as follows:
--------------------------------------------------------------
Dec 31, 2012
----------------------------------------------------------------------------
Loans and Fair Financial
receivables value liabilities
at through Derivatives at
Asset amortized profit or used for amortized
(liability) cost loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 1,197 $ - $ - $ - $ 1,197
Accounts
payable - - - (465) (465)
Accrued
liabilities - - - (2,273) (2,273)
Other long-
term
liabilities - 4 (261) (79) (336)
Long-term debt
(1) - - - (8,736) (8,736)
----------------------------------------------------------------------------
$ 1,197 $ 4 $ (261) $ (11,553) $(10,613)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2011
----------------------------------------------------------------------------
Loans and Fair Financial
receivables value liabilities
at through Derivatives at
Asset amortized profit used for amortized
(liability) cost or loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 2,077 $ - $ - $ - $ 2,077
Accounts
payable - - - (526) (526)
Accrued
liabilities - - - (2,347) (2,347)
Other long-
term
liabilities - (38) (236) (75) (349)
Long-term debt
(1) - - - (8,571) (8,571)
----------------------------------------------------------------------------
$ 2,077 $ (38) $ (236) $ (11,519) $ (9,716)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
The carrying amount of the Company's financial instruments
approximates their fair value, except for fixed rate long-term debt
as noted below. The fair values of the Company's other long-term
liabilities and fixed rate long-term debt are outlined below:
---------------------------------------------
Dec 31, 2012
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term liabilities $ (257) $ - $ (257)
Fixed rate long-term debt (2)
(3) (4) (7,765) (9,118) -
----------------------------------------------------------------------------
$ (8,022) $ (9,118) $ (257)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2011
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term liabilities $ (274) $ - $ (274)
Fixed rate long-term debt (2)
(3) (4) (7,775) (9,120) -
----------------------------------------------------------------------------
$ (8,049) $ (9,120) $ (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes financial assets and liabilities where the carrying amount
approximates fair value due to the liquid nature of the asset or
liability (cash and cash equivalents, accounts receivable, accounts
payable and accrued liabilities).
(2) The carrying amount of US$350 million of 4.90% unsecured notes due
December 2014 was adjusted by $19 million to reflect the fair value
impact of hedge accounting. At December 31, 2011, the carrying
amounts of US$350 million of 5.45% unsecured notes due October 2012
and US$350 million of 4.90% unsecured notes due December 2014
were adjusted by $31 million to reflect the fair value impact of
hedge accounting.
(3) The fair value of fixed rate long-term debt has been determined based on
quoted market prices.
(4) Includes the current portion of long-term debt.
The following provides a summary of the carrying amounts of
derivative contracts held and a reconciliation to the Company's
consolidated balance sheets.
-------------
Dec 31, Dec 31,
Asset (liability) 2012 2011
----------------------------------------------------------------------------
Derivatives held for trading
Crude oil price collars $ (16) $ (13)
Foreign currency forward contracts 20 (25)
Cash flow hedges
Cross currency swaps (261) (236)
----------------------------------------------------------------------------
$ (257) $ (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Included within:
Current portion of other long-term liabilities $ (4) $ (43)
Other long-term liabilities (253) (231)
----------------------------------------------------------------------------
$ (257) $ (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During 2012, the Company recognized a gain of $1 million
(December 31, 2011 - loss of $2 million) related to ineffectiveness
arising from cash flow hedges.
Risk Management
The Company uses derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures.
These financial instruments are entered into solely for hedging
purposes and are not used for speculative purposes.
The estimated fair value of derivative financial instruments has
been determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values
determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows and discount
rates. In determining these assumptions, the Company primarily
relied on external, readily-observable market inputs including
quoted commodity prices and volatility, interest rate yield curves,
and foreign exchange rates. The resulting fair value estimates may
not necessarily be indicative of the amounts that could be realized
or settled in a current market transaction and these differences
may be material.
The changes in estimated fair values of derivative financial
instruments included in the risk management asset (liability) were
recognized in the financial statements as follows:
-------------
Year Ended Year Ended
Dec 31, Dec 31,
Asset (liability) 2012 2011
----------------------------------------------------------------------------
Balance - beginning of year $ (274) $ (485)
Net change in fair value of outstanding derivative
financial instruments attributable to:
Risk management activities 42 128
Foreign exchange (53) 42
Other comprehensive income 28 41
----------------------------------------------------------------------------
Balance - end of year (257) (274)
Less: current portion (4) (43)
----------------------------------------------------------------------------
$ (253) $ (231)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net (gains) losses from risk management activities were as
follows:
Three Months Ended Year Ended
-------------------------- -------------
Dec 31 Dec 31 Dec 31 Dec 31
2012 2011 2012 2011
----------------------------------------------------------------------------
Net realized risk
management (gain) loss $ (8) $ 20 $ 162 $ 101
Net unrealized risk
management loss (gain) 8 58 (42) (128)
----------------------------------------------------------------------------
$ - $ 78 $ 120 $ (27)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial Risk Factors
a) Market risk
Market risk is the risk that the fair value or future cash flows
of a financial instrument will fluctuate because of changes in
market prices. The Company's market risk is comprised of commodity
price risk, interest rate risk, and foreign currency exchange
risk.
Commodity price risk management
The Company periodically uses commodity derivative financial
instruments to manage its exposure to commodity price risk
associated with the sale of its future crude oil and natural gas
production and with natural gas purchases. At December 31, 2012,
the Company had the following derivative financial instruments
outstanding to manage its commodity price risk:
Sales contracts
Weighted average
Remaining term Volume price Index
----------------------------------------------------------------------------
Crude oil
Crude oil price
collars (1) Jan 2013 - Jun 2013 50,000 bbl/d US$80.00 - US$145.07 Brent
Jan 2013 - Dec 2013 50,000 bbl/d US$80.00 - US$135.59 Brent
Jan 2013 - Dec 2013 50,000 bbl/d US$80.00 - US$97.73 WTI
Jan 2013 - Dec 2013 50,000 bbl/d US$80.00 - US$110.34 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to December 31, 2012, the Company entered into an additional
50,000 bbl/d of US$80 - US$111.05 WTI collars for the period April to
December 2013 and an additional 50,000 bbl/d of US$80 - US$132.18 Brent
collars for the period July to December 2013.
During the fourth quarter of 2012, US$19 million of put option
costs were settled.
The Company's outstanding commodity derivative financial
instruments are expected to be settled monthly based on the
applicable index pricing for the respective contract month.
Interest rate risk management
The Company is exposed to interest rate price risk on its fixed
rate long-term debt and to interest rate cash flow risk on its
floating rate long-term debt. The Company periodically enters into
interest rate swap contracts to manage its fixed to floating
interest rate mix on long-term debt. The interest rate swap
contracts require the periodic exchange of payments without the
exchange of the notional principal amounts on which the payments
are based. At December 31, 2012, the Company had no interest rate
swap contracts outstanding.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated long-term
debt and working capital. The Company is also exposed to foreign
currency exchange rate risk on transactions conducted in other
currencies in its subsidiaries and in the carrying value of its
foreign subsidiaries. The Company periodically enters into cross
currency swap contracts and foreign currency forward contracts to
manage known currency exposure on US dollar denominated long-term
debt and working capital. The cross currency swap contracts require
the periodic exchange of payments with the exchange at maturity of
notional principal amounts on which the payments are based. At
December 31, 2012, the Company had the following cross currency
swap contracts outstanding:
Exchange
rate Interest Interest
Remaining term Amount (US$/C$) rate (US$) rate (C$)
----------------------------------------------------------------------------
Cross
currency
Swaps Jan 2013 - Aug 2016 US$250 1.116 6.00% 5.40%
Jan 2013 - May 2017 US$1,100 1.170 5.70% 5.10%
Jan 2013 - Nov 2021 US$500 1.022 3.45% 3.96%
Jan 2013 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All cross currency swap derivative financial instruments
designated as hedges at December 31, 2012, were classified as cash
flow hedges.
In addition to the cross currency swap contracts noted above, at
December 31, 2012, the Company had US$2,821 million of foreign
currency forward contracts outstanding, with terms of approximately
30 days or less.
b) Credit Risk
Credit risk is the risk that a party to a financial instrument
will cause a financial loss to the Company by failing to discharge
an obligation.
Counterparty credit risk management
The Company's accounts 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, 2012, substantially all of the Company's accounts
receivable were due within normal trade terms.
The Company is also exposed to possible losses in the event of
nonperformance by counterparties to derivative financial
instruments; however, the Company manages this credit risk by
entering into agreements with counterparties that are substantially
all investment grade financial institutions and other entities. At
December 31, 2012, the Company had net risk management assets of
$18 million with specific counterparties related to derivative
financial instruments (December 31, 2011 - $nil).
c) Liquidity Risk
Liquidity risk is the risk that the Company will encounter
difficulty in meeting obligations associated with financial
liabilities.
Management of liquidity risk requires the Company to maintain
sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating
activities, available credit facilities, and access to debt capital
markets, to meet obligations as they become due. The Company
believes it has adequate bank credit facilities to provide
liquidity to manage fluctuations in the timing of the receipt
and/or disbursement of operating cash flows.
The maturity dates for financial liabilities are as follows:
1 to less 2 to less
Less than than than
1 year 2 years 5 years Thereafter
----------------------------------------------------------------------------
Accounts payable $ 465 $ - $ - $ -
Accrued liabilities $ 2,273 $ - $ - $ -
Risk management $ 4 $ 53 $ 123 $ 77
Other long-term liabilities $ 22 $ 24 $ 33 $ -
Long-term debt (1) $ 798 $ 846 $ 2,714 $ 4,430
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does not reflect
fair value adjustments, interest, original issue discounts or
transaction costs.
14. COMMITMENTS AND CONTINGENCIES
The Company has committed to certain payments as follows:
2013 2014 2015 2016 2017 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 231 $ 218 $ 204 $ 135 $ 117 $ 788
Offshore equipment
operating leases and
offshore drilling $ 156 $ 135 $ 104 $ 76 $ 57 $ 65
Office leases $ 33 $ 34 $ 32 $ 33 $ 35 $ 262
Other $ 173 $ 95 $ 43 $ 10 $ 2 $ 7
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In addition to the commitments disclosed above, the Company has
entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These
contracts can be cancelled by the Company upon notice without
penalty, subject to the costs incurred up to and in respect of the
cancellation.
The Company is a defendant and plaintiff in a number of legal
actions arising in the normal course of business. In addition, the
Company is subject to certain contractor construction claims. The
Company believes that any liabilities that might arise pertaining
to any such matters would not have a material effect on its
consolidated financial position.
15. SEGMENTED INFORMATION
Exploration and Production
North America North Sea
(millions of Three Months Three Months
Canadian Ended Year Ended Ended Year Ended
dollars,unaudited) Dec 31 Dec 31 Dec 31 Dec 31
--------------------------------------------------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales 3,006 3,163 11,607 11,806 215 317 928 1,224
Less: royalties (277) (482)(1,268)(1,538) - (1) (2) (3)
----------------------------------------------------------------------------
Segmented revenue 2,729 2,681 10,339 10,268 215 316 926 1,221
----------------------------------------------------------------------------
Segmented expenses
Production 557 516 2,165 1,933 100 103 402 412
Transportation and
blending 735 575 2,735 2,301 2 3 10 13
Depletion,
depreciation and
amortization (note
3) 965 726 3,413 2,840 74 65 296 249
Asset retirement
obligation
accretion 21 17 85 70 7 9 27 33
Realized risk
management
activities (8) 20 162 101 - - - -
Horizon asset
impairment
provision - - - - - - - -
Insurance recovery -
property damage
(note 7) - - - - - - - -
Insurance recovery -
business
interruption (note
7) - - - - - - - -
Equity loss from
jointly controlled
entity - - - - - - - -
----------------------------------------------------------------------------
Total segmented
expenses 2,270 1,854 8,560 7,245 183 180 735 707
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following 459 827 1,779 3,023 32 136 191 514
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and other
financing costs
Unrealized risk
management
activities
Foreign exchange
loss (gain)
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Current income tax
expense
Deferred income tax
(recovery) expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exploration and Production
Total Exploration and
Offshore Africa Production
(millions of Three Months Three Months
Canadian Ended Year Ended Ended Year Ended
dollars,unaudited) Dec 31 Dec 31 Dec 31 Dec 31
--------------------------------------------------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales 158 308 773 946 3,379 3,788 13,308 13,976
Less: royalties (53) (46) (199) (114) (330) (529)(1,469)(1,655)
----------------------------------------------------------------------------
Segmented revenue 105 262 574 832 3,049 3,259 11,839 12,321
----------------------------------------------------------------------------
Segmented expenses
Production 39 66 163 186 696 685 2,730 2,531
Transportation and
blending - - 1 1 737 578 2,746 2,315
Depletion,
depreciation and
amortization (note
3) 58 72 165 242 1,097 863 3,874 3,331
Asset retirement
obligation
accretion 2 2 7 7 30 28 119 110
Realized risk
management
activities - - - - (8) 20 162 101
Horizon asset
impairment
provision - - - - - - - -
Insurance recovery -
property damage
(note 7) - - - - - - - -
Insurance recovery -
business
interruption (note
7) - - - - - - - -
Equity loss from
jointly controlled
entity - - - - - - - -
----------------------------------------------------------------------------
Total segmented
expenses 99 140 336 436 2,552 2,174 9,631 8,388
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following 6 122 238 396 497 1,085 2,208 3,933
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and other
financing costs
Unrealized risk
management
activities
Foreign exchange
loss (gain)
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Current income tax
expense
Deferred income tax
(recovery) expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil Sands Mining and
Upgrading Midstream
(millions of Three Months Three Months
Canadian Ended Year Ended Ended Year Ended
dollars,unaudited) Dec 31 Dec 31 Dec 31 Dec 31
--------------------------------------------------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales 675 1,005 2,871 1,521 26 22 93 88
Less: royalties (29) (41) (137) (60) - - - -
----------------------------------------------------------------------------
Segmented revenue 646 964 2,734 1,461 26 22 93 88
----------------------------------------------------------------------------
Segmented expenses
Production 372 344 1,504 1,127 8 7 29 26
Transportation and
blending 15 16 61 62 - - - -
Depletion,
depreciation and
amortization (note
3) 114 133 447 266 2 2 7 7
Asset retirement
obligation
accretion 8 5 32 20 - - - -
Realized risk
management
activities - - - - - - - -
Horizon asset
impairment
provision - - - 396 - - - -
Insurance recovery -
property damage
(note 7) - 3 - (393) - - - -
Insurance recovery -
business
interruption (note
7) - (16) - (333) - - - -
Equity loss from
jointly controlled
entity - - - - 3 - 9 -
----------------------------------------------------------------------------
Total segmented
expenses 509 485 2,044 1,145 13 9 45 33
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following 137 479 690 316 13 13 48 55
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and other
financing costs
Unrealized risk
management
activities
Foreign exchange
loss (gain)
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Current income tax
expense
Deferred income tax
(recovery) expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment elimination
and other Total
(millions of Three Months Three Months
Canadian Ended Year Ended Ended Year Ended
dollars,unaudited) Dec 31 Dec 31 Dec 31 Dec 31
--------------------------------------------------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales (21) (27) (77) (78) 4,059 4,788 16,195 15,507
Less: royalties - - - - (359) (570)(1,606)(1,715)
----------------------------------------------------------------------------
Segmented revenue (21) (27) (77) (78) 3,700 4,218 14,589 13,792
----------------------------------------------------------------------------
Segmented expenses
Production (4) (2) (14) (13) 1,072 1,034 4,249 3,671
Transportation and
blending (14) (12) (55) (50) 738 582 2,752 2,327
Depletion,
depreciation and
amortization (note
3) - - - - 1,213 998 4,328 3,604
Asset retirement
obligation
accretion - - - - 38 33 151 130
Realized risk
management
activities - - - - (8) 20 162 101
Horizon asset
impairment
provision - - - - - - - 396
Insurance recovery -
property damage
(note 7) - - - - - 3 - (393)
Insurance recovery -
business
interruption (note
7) - - - - - (16) - (333)
Equity loss from
jointly controlled
entity - - - - 3 - 9 -
----------------------------------------------------------------------------
Total segmented
expenses (18) (14) (69) (63) 3,056 2,654 11,651 9,503
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following (3) (13) (8) (15) 644 1,564 2,938 4,289
----------------------------------------------------------------------------
Non-segmented
expenses
Administration 64 47 270 235
Share-based
compensation (41) 207 (214) (102)
Interest and other
financing costs 83 83 364 373
Unrealized risk
management
activities 8 58 (42) (128)
Foreign exchange
loss (gain) 58 (106) (49) 1
----------------------------------------------------------------------------
Total non-segmented
expenses 172 289 329 379
----------------------------------------------------------------------------
Earnings before
taxes 472 1,275 2,609 3,910
Current income tax
expense 189 299 747 860
Deferred income tax
(recovery) expense (69) 144 (30) 407
----------------------------------------------------------------------------
Net earnings 352 832 1,892 2,643
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital Expenditures (1)
Year Ended
----------------------------------------------------
Dec 31, 2012
----------------------------------------------------------------------------
Non cash
Net and fair value Capitalized
expenditures changes(2) costs
----------------------------------------------------------------------------
Exploration and
evaluation assets
Exploration and
Production
North America $ 295 $ (173) $ 122
North Sea - - -
Offshore Africa 14 - 14
----------------------------------------------------------------------------
$ 309 $ (173) $ 136
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Property, plant and
equipment
Exploration and
Production
North America $ 3,831 $ 373 $ 4,204
North Sea 254 263 517
Offshore Africa 50 17 67
----------------------------------------------------------------------------
4,135 653 4,788
Oil Sands Mining and
Upgrading (3) (4) 1,610 142 1,752
Midstream 14 - 14
Head office 36 - 36
----------------------------------------------------------------------------
$ 5,795 $ 795 $ 6,590
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Year Ended
---------------------------------------------------
Dec 31, 2011
---------------------------------------------------------------------------
Non cash and
Net fair value Capitalized
expenditures changes(2) costs
---------------------------------------------------------------------------
Exploration and
evaluation assets
Exploration and
Production
North America $ 309 $ (233) $ 76
North Sea 1 (6) (5)
Offshore Africa 2 - 2
---------------------------------------------------------------------------
$ 312 $ (239) $ 73
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Property, plant and
equipment
Exploration and
Production
North America $ 4,427 $ 832 $ 5,259
North Sea 226 15 241
Offshore Africa 31 16 47
---------------------------------------------------------------------------
4,684 863 5,547
Oil Sands Mining and
Upgrading (3) (4) 1,182 (140) 1,042
Midstream 5 2 7
Head office 18 - 18
---------------------------------------------------------------------------
$ 5,889 $ 725 $ 6,614
---------------------------------------------------------------------------
---------------------------------------------------------------------------
(1) This table provides a reconciliation of capitalized costs including
derecognitions and does not include the impact of foreign exchange
adjustments.
(2) Asset retirement obligations, deferred income tax adjustments related to
differences between carrying amounts and tax values, transfers of
exploration and evaluation assets, and other fair value adjustments.
(3) Net expenditures for Oil Sands Mining and Upgrading also include
capitalized interest and share-based compensation.
(4) During the first quarter of 2011, the Company derecognized certain
property, plant and equipment related to the coker fire at Horizon in
the amount of $411 million. This amount was included in non cash and
fair value changes.
Segmented Assets
Total Assets
--------------------------
Dec 31 Dec 31
2012 2011
----------------------------------------------------------------------------
Exploration and Production
North America $ 29,012 $ 28,233
North Sea 1,993 1,809
Offshore Africa 924 1,070
Other 36 23
Oil Sands Mining and Upgrading 16,291 15,433
Midstream 636 642
Head office 88 68
----------------------------------------------------------------------------
$ 48,980 $ 47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUPPLEMENTARY INFORMATION
INTEREST COVERAGE RATIOS
The following financial ratios are provided in connection with
the Company's continuous offering of medium-term notes pursuant to
the short form prospectus dated October 2011. These ratios are
based on the Company's interim consolidated financial statements
that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the twelve month period ended December
31, 2012:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 6.4x
Cash flow from operations (2) 15.3x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net earnings plus income taxes and interest expense excluding current
and deferred PRT expense and other taxes; divided by the sum of interest
expense and capitalized interest.
(2) Cash flow from operations plus current income taxes and interest expense
excluding current PRT expense and other taxes; divided by the sum of
interest expense and capitalized interest.
CONFERENCE CALL
A conference call will be held at 9:00 a.m. Mountain Time, 11:00
a.m. Eastern Time on Thursday, March 7, 2013. The North American
conference call number is 1-877-240-9772 and the outside North
American conference call number is 001-416-340-8527. Please call in
about 10 minutes before the starting time in order to be patched
into the call.
A taped rebroadcast will be available until 6:00 p.m. Mountain
Time, Thursday, March 14, 2013. To access the rebroadcast in North
America, dial 1-800-408-3053. Those outside of North America, dial
001-905-694-9451. The pass code to use is 6854115.
WEBCAST
The conference call will also be broadcast live on the internet
and may be accessed through the Canadian Natural website at
www.cnrl.com.
Contacts: John G. Langille Vice-Chairman Steve W. Laut President
Corey B. Bieber Vice-President, Finance & Investor Relations
Canadian Natural Resources Limited 2500, 855 2nd Street S.W.
Calgary, Alberta, T2P 4J8 Canada Phone: (403) 514-7777 Fax: (403)
514-7888 (FAX)ir@cnrl.com www.cnrl.com
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