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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| TSXV:SCO | TSX Venture | Common Stock |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 0 | - |
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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.
FOR FURTHER INFORMATION PLEASE CONTACT:
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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